Regulation of Fuels and Fuel Additives: Identification of Additional Qualifying Renewable Fuel Pathways Under the Renewable Fuel Standard Program, 700-727 [2011-31580]
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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations
40 CFR Part 80
[EPA–HQ–OAR–2011–0542; FRL–9502–2]
RIN 2060–AR07
Regulation of Fuels and Fuel
Additives: Identification of Additional
Qualifying Renewable Fuel Pathways
Under the Renewable Fuel Standard
Program
Environmental Protection
Agency (EPA).
ACTION: Direct final rule.
AGENCY:
EPA is issuing a direct final
rule identifying additional fuel
pathways that EPA has determined meet
the biomass-based diesel, advanced
biofuel or cellulosic biofuel lifecycle
greenhouse gas (GHG) reduction
requirements specified in Clean Air Act
section 211(o), the Renewable Fuel
Standard Program, as amended by the
Energy Independence and Security Act
of 2007 (EISA). This direct final rule
describes EPA’s evaluation of biofuels
produced from camelina oil, energy
cane, giant reed, and napiergrass; it also
includes an evaluation of renewable
gasoline and renewable gasoline
blendstocks, as well as biodiesel from
esterification, and clarifies our
definition of renewable diesel. We are
also finalizing two changes to regulation
that were proposed on July 1, 2011(76
FR 38844). The first change adds ID
letters to pathways to facilitate
references to specific pathways. The
second change adds ‘‘rapeseed’’ to the
existing pathway for renewable fuel
made from canola oil.
This direct final rule adds these
pathways to Table in regulation as
pathways which have been determined
to meet one or more of the GHG
reduction thresholds specified in CAA
211(o), and assigns each pathway a
corresponding D-Code. It allows
producers or importers of fuel produced
pursuant to these pathways to generate
Renewable Identification Numbers
(RINs), providing that the fuel meets the
other requirements specified in the RFS
regulations to qualify it as renewable
fuel.
DATES: This rule is effective on March 5,
2012 without further notice, unless EPA
receives adverse comment or a hearing
request by February 6, 2012. If EPA
receives a timely adverse comment or a
hearing request, we will publish a
withdrawal in the Federal Register
informing the public that the portions of
the rule with adverse comment will not
take effect.
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SUMMARY:
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Submit your comments,
identified by Docket ID No. EPA–HQ–
OAR–2011–0542, by one of the
following methods:
• www.regulations.gov: Follow the
on-line instructions for submitting
comments.
• Email: a-and-r-docket@epa.gov,
Attention Air and Radiation Docket ID
EPA–HQ–OAR–2011–0542
• Fax: [Insert fax number].
• Mail: Air and Radiation Docket,
Docket No. EPA–HQ–OAR–2011–0542,
Environmental Protection Agency,
Mailcode: 6406J, 1200 Pennsylvania
Ave. NW., Washington, DC 20460.
• Hand Delivery: EPA Docket Center,
EPA/DC, EPA West, Room 3334, 1301
Constitution Ave. NW., Washington,
DC, 20460, Attention Air and Radiation
Docket, ID No. EPA–HQ–OAR–2011–
0542. Such deliveries are only accepted
during the Docket’s normal hours of
operation, and special arrangements
should be made for deliveries of boxed
information.
Instructions: Direct your comments to
Docket ID No. EPA–HQ–OAR–2011–
0542. EPA’s policy is that all comments
received will be included in the public
docket without change and may be
made available online at
www.regulations.gov, including any
personal information provided, unless
the comment includes information
claimed to be Confidential Business
Information (CBI) or other information
whose disclosure is restricted by statute.
Do not submit information that you
consider to be CBI or otherwise
protected through www.regulations.gov
or email. The www.regulations.gov Web
site is an ‘‘anonymous access’’ system,
which means EPA will not know your
identity or contact information unless
you provide it in the body of your
comment. If you send an email
comment directly to EPA without going
through www.regulations.gov your email
address will be automatically captured
and included as part of the comment
that is placed in the public docket and
made available on the Internet. If you
submit an electronic comment, EPA
recommends that you include your
name and other contact information in
the body of your comment and with any
disk or CD–ROM you submit. If EPA
cannot read your comment due to
technical difficulties and cannot contact
you for clarification, EPA may not be
able to consider your comment.
Electronic files should avoid the use of
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encryption, and be free of any defects or
viruses. For additional information
about EPA’s public docket visit the EPA
Docket Center homepage at https://
www.epa.gov/epahome/dockets.htm.
ADDRESSES:
ENVIRONMENTAL PROTECTION
AGENCY
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Docket: All documents in the docket
are listed in the www.regulations.gov
index. Although listed in the index,
some information is not publicly
available, e.g., CBI or other information
whose disclosure is restricted by statute.
Certain other material, such as
copyrighted material, will be publicly
available only in hard copy. Publicly
available docket materials are available
either electronically in
www.regulations.gov or in hard copy at
the Air and Radiation Docket and
Information Center, EPA/DC, EPA West,
Room 3334, 1301 Constitution Ave.
NW., Washington, DC. The Public
Reading Room is open from 8:30 a.m. to
4:30 p.m., Monday through Friday,
excluding legal holidays. The telephone
number for the Public Reading Room is
(202) 566–1744, and the telephone
number for the Air Docket is (202) 566–
1742).
FOR FURTHER INFORMATION CONTACT:
Vincent Camobreco, Office of
Transportation and Air Quality
(MC6401A), Environmental Protection
Agency, 1200 Pennsylvania Ave. NW.,
Washington, DC 20460; telephone
number: (202) 564–9043; fax number:
(202) 564–1686; email address:
camobreco.vincent@epa.gov.
SUPPLEMENTARY INFORMATION:
I. Why is EPA using a direct final rule?
EPA is publishing this rule without a
prior proposed rule because we view
this as a noncontroversial action. These
new pathway determinations did not
require new agricultural sector
modeling and involved relatively
straightforward analyses that largely
relied upon work done for the RFS2
final rule. If EPA receives relevant
adverse comment or a hearing request
on a distinct provision of this
rulemaking, we will publish a timely
withdrawal in the Federal Register
indicating which portion of the rule is
being withdrawn. Any distinct
amendment, paragraph, or section of
today’s rule not withdrawn will become
effective on the date set out above.
In the ‘‘Proposed Rules’’ section of
today’s Federal Register, we are
publishing a separate document that
will serve as the proposed rule to
update Table 1 of § 80.1426 to add any
additional renewable fuel production
pathways or regulatory provisions
which may be withdrawn from the
direct final rule. We will not institute a
second comment period on this action.
Any parties interested in commenting
must do so at this time. For further
information about commenting on this
rule, see the ADDRESSES section of this
document. We will address all public
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comments in any subsequent final rule
based on the proposed rule.
1
2
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SIC 2
Codes
324110
325193
325199
424690
424710
424720
454319
2911
2869
2869
5169
5171
5172
5989
transportation fuels, including gasoline
and diesel fuel or renewable fuels such
as ethanol and biodiesel. Regulated
categories and entities affected by this
action include:
Examples of potentially regulated entities
Petroleum Refineries.
Ethyl alcohol manufacturing.
Other basic organic chemical manufacturing.
Chemical and allied products merchant wholesalers.
Petroleum bulk stations and terminals.
Petroleum and petroleum products merchant wholesalers.
Other fuel dealers.
North American Industry Classification System (NAICS)
Standard Industrial Classification (SIC) system code.
This table is not intended to be
exhaustive, but rather provides a guide
for readers regarding entities likely to be
regulated by this action. This table lists
the types of entities that EPA is now
aware could be potentially regulated by
this action. Other types of entities not
listed in the table could also be
regulated. To determine whether your
entity is regulated by this action, you
should carefully examine the
applicability criteria of Part 80, subparts
D, E and F of title 40 of the Code of
Federal Regulations. If you have any
question regarding applicability of this
action to a particular entity, consult the
person in the preceding FOR FURTHER
INFORMATION CONTACT section above.
III. What should I consider as I prepare
my comments for EPA?
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Entities potentially affected by this
action are those involved with the
production, distribution, and sale of
NAICS 1
Codes
Category
Industry
Industry
Industry
Industry
Industry
Industry
Industry
II. Does this action apply to me?
701
A. Submitting information claimed as
CBI. Do not submit information you
claim as CBI to EPA through
www.regulations.gov or email. Clearly
mark the part or all of the information
that you claim to be CBI. For CBI
information in a disk or CD ROM that
you mail to EPA, mark the outside of the
disk or CD ROM as CBI and then
identify electronically within the disk or
CD ROM the specific information that is
claimed as CBI). In addition to one
complete version of the comment that
includes information claimed as CBI, a
copy of the comment that does not
contain the information claimed as CBI
must be submitted for inclusion in the
public docket. Information so marked
will not be disclosed except in
accordance with procedures set forth in
40 CFR part 2.
B. Tips for Preparing Your Comments.
When submitting comments, remember
to:
• Identify the rulemaking by docket
number and other identifying
information (subject heading, Federal
Register date and page number).
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• Follow directions—The agency may
ask you to respond to specific questions
or organize comments by referencing a
Code of Federal Regulations (CFR) part
or section number.
• Explain why you agree or disagree;
suggest alternatives and substitute
language for your requested changes.
• Describe any assumptions and
provide any technical information and/
or data that you used.
• If you estimate potential costs or
burdens, explain how you arrived at
your estimate in sufficient detail to
allow for it to be reproduced.
• Provide specific examples to
illustrate your concerns, and suggest
alternatives.
• Explain your views as clearly as
possible, avoiding the use of profanity
or personal threats.
• Make sure to submit your
comments by the comment period
deadline identified.
C. Docket Copying Costs. You may be
charged a reasonable fee for
photocopying docket materials, as
provided in 40 CFR part 2.
IV. Identification of additional
qualifying renewable fuel pathways
under the renewable fuel standard
(RFS) program
EPA is issuing a direct final rule to
identify in the RFS regulations
additional renewable fuel production
pathways that we have determined meet
the greenhouse gas (GHG) reduction
requirements of the RFS program. This
direct final rule describes EPA’s
evaluation of:
Camelina Oil (New Feedstock)
• Biodiesel and renewable diesel
(including jet fuel and heating oil) —
qualifying as biomass-based diesel and
advanced biofuel
• Naphtha and liquefied petroleum
gas (LPG) — qualifying as advanced
biofuel
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Energy Cane, Giant Reed, and
Napiergrass Cellulosic Biomass (New
Feedstocks)
• Ethanol, renewable diesel
(including renewable jet fuel and
heating oil), and naphtha — qualifying
as cellulosic biofuel
Renewable Gasoline and Renewable
Gasoline Blendstock (New Fuel Types)
• Produced from crop residue, slash,
pre-commercial thinnings, tree residue,
annual cover crops, and cellulosic
components of separated yard waste,
separated food waste, and separated
municipal solid waste (MSW)
• Using the following processes — all
utilizing natural gas, biogas, and/or
biomass as the only process energy
sources — qualifying as cellulosic
biofuel:
Æ Thermochemical pyrolysis
Æ Thermochemical gasification
Æ Biochemical direct fermentation
Æ Biochemical fermentation with
catalytic upgrading
Æ Any other process that uses biogas
and/or biomass as the only process
energy sources
Esterification (New Production Process)
• Process used to produce biodiesel
from soy bean oil, oil from annual
covercrops, algal oil, biogenic waste
oils/fats/greases, non-food grade corn
oil, Canola/rapeseed oil, and camelina
oil—qualifying as biomass-based diesel
and advanced biofuel
This direct final rule adds these
pathways to Table 1 to § 80.1426 and
assigns each pathway one or more D–
Codes. This final rule allows producers
or importers of fuel produced under
these pathways to generate Renewable
Identification Numbers (RINs) in
accordance with the RFS regulations,
providing that the fuel meets other
definitional criteria for renewable fuel.
Determining whether a fuel pathway
satisfies the CAA’s lifecycle GHG
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reduction thresholds for renewable fuels
requires a comprehensive evaluation of
the lifecycle GHG emissions of the
renewable fuel as compared to the
lifecycle GHG emissions of the baseline
gasoline or diesel fuel that it replaces.
As mandated by CAA section 211(o), the
GHG emissions assessments must
evaluate the aggregate quantity of GHG
emissions (including direct emissions
and significant indirect emissions such
as significant emissions from land use
changes) related to the full fuel
lifecycle, including all stages of fuel and
feedstock production, distribution, and
use by the ultimate consumer.
In examining the full lifecycle GHG
impacts of renewable fuels for the RFS
program, EPA considers the following:
• Feedstock production—based on
agricultural sector models that include
direct and indirect impacts of feedstock
production
• Fuel production—including process
energy requirements, impacts of any raw
materials used in the process, and
benefits from co-products produced.
• Fuel and feedstock distribution—
including impacts of transporting
feedstock from production to use, and
transport of the final fuel to the
consumer.
• Use of the fuel—including
combustion emissions from use of the
fuel in a vehicle.
Many of the pathways evaluated in
this rulemaking rely on a comparison to
the lifecycle GHG analysis work that
was done as part of the Renewable Fuel
Standard Program (RFS2) Final Rule,
published March 26, 2010. The
evaluations here rely on comparisons to
the existing analysis. EPA plans to
periodically review and revise the
methodology and assumptions
associated with calculating the GHG
emissions from all renewable fuel
pathways.
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A. Analysis of Lifecycle Greenhouse Gas
Emissions for Biodiesel, Renewable
Diesel, Jet Fuel, Naphtha, and Liquefied
Petroleum Gas (LPG) Produced From
Camelina Oil
1. Feedstock Production
Camelina sativa (camelina) is an
oilseed crop within the flowering plant
family Brassicaceae that is native to
Northern Europe and Central Asia.
Camelina’s suitability to northern
climates and low moisture requirements
allows it to be grown in areas that are
unsuitable for other major oilseed crops
such as soybeans, sunflower, and
canola/rapeseed. Camelina also requires
the use of little to no tillage.1 Compared
1 Putnam, D.H., J.T. Budin, L.A. Field, and W.M.
Breene. 1993. Camelina: A promising low-input
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to many other oilseeds, camelina has a
relatively short growing season (less
than 100 days), and can be grown either
as a spring annual or in the winter in
milder climates. 2 3 Camelina can also be
used to break the continuous planting
cycle of certain grains, effectively
reducing the disease, insect, and weed
pressure in fields planted with such
grains (like wheat) in the following
year.4
Although camelina has been
cultivated in Europe in the past for use
as food, medicine, and as a source for
lamp oil, commercial production using
modern agricultural techniques has
been limited.5 In addition to being used
as a renewable fuel feedstock, small
quantities of camelina (less than 5% of
total U.S. camelina production) are
currently used as a dietary supplement
and in the cosmetics industry.
Approximately 95% of current US
production of camelina has been used
for testing purposes to evaluate its use
as a feedstock to produce primarily jet
fuel.6 The FDA has not approved
camelina for food uses, although it has
approved the inclusion of certain
quantities of camelina meal in
commercial feed.7
Camelina is currently being grown on
approximately 50,000 acres of land in
the U.S., primarily in Montana, eastern
Washington, and the Dakotas.8 USDA
does not systematically collect camelina
production information; therefore data
on historical acreage is limited.
However, available information
indicates that camelina has been grown
on trial plots in 12 U.S. states.9
For the purposes of analyzing the
lifecycle GHG emissions of camelina,
EPA has considered the likely
production pattern for camelina grown
for biofuel production. Given the
information currently available,
camelina is expected to be primarily
planted in the U.S. as a rotation crop on
acres that would otherwise remain
fallow during the camelina planting.
Since substituting fallow land with
camelina production would not
typically displace another crop, EPA
does not believe new acres would need
to be brought into agricultural use to
increase camelina production. In
addition, camelina currently has only
limited high-value niche markets for
uses other than renewable fuels. Unlike
commodity crops that are tracked by
USDA, camelina does not have a wellestablished, internationally traded
market that would be significantly
affected by an increase in the use of
camelina to produce biofuels. For these
reasons, which are described in more
detail below, EPA has determined that
production of camelina-based biofuels is
not expected to result in significant
GHG emissions related to direct land
use change since it is grown on fallow
land. Furthermore, due to the limited
non-biofuel uses for camelina,
production of camelina-based biofuels is
not expected to have a significant
impact on other agricultural crop
production or commodity markets
(either camelina or other crop markets)
and consequently would not result in
significant GHG emissions related to
indirect land use change. To the extent
camelina-based biofuel production
decreases the demand for alternative
biofuels, some with higher GHG
emissions, this biofuel could have some
beneficial GHG impact. However, it is
uncertain which mix of biofuel sources
the market will demand so this potential
GHG impact cannot be quantified.
oilseed. p. 314–322. In: J. Janick and J.E. Simon
(eds.), New crops. Wiley, New York.
2 Moser, B.R., Vaughn, S.F. 2010. Evaluation of
Alkyl Esters from Camelina Sativa Oil as Biodiesel
and as Blend Components in Ultra Low Sulfur
Diesel Fuel. Bioresource Technology. 101:646–653.
3 McVay, K.A., and P.F. Lamb. 2008. Camelina
production in Montana. MSU Ext. MT200701AG
(revised). https://msuextension.org/publica™tions/
AgandNaturalResources/MT200701AG.pdf.
4 Putnam et al., 1993.
5 Lafferty, Ryan M., Charlie Rife and Gus Foster.
2009. Spring camelina production guide for the
Central High Plains. Blue Sun Biodiesel special
publication. Blue Sun Agriculture Research &
Development, Golden, CO. https://
www.gobluesun.com/upload/Spring%20Camelina%20Production%20Guide%202009.pdf.
6 Telephone conversation with Scott Johnson,
Sustainable Oils, January 11, 2011.
7 See https://agr.mt.gov/camelina/FDAletter11–
09.pdf.
8 McCormick, Margaret. ‘‘Oral Comments of
Targeted Growth, Incorporated’’ Submitted to the
EPA on June 9, 2009.
9 See https://www.camelinacompany.com/
Marketing/PressRelease.aspx?Id=25.
a. Growing Practices
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Current market conditions indicate
that camelina will most likely be grown
in rotation with wheat on dryland wheat
acres replacing a period that they would
otherwise be left fallow.10 In areas with
lower precipitation, dryland wheat
farmers currently leave acres fallow
once every three to four years to allow
additional moisture and nutrients to
accumulate and to control pests. Current
research indicates that camelina could
be introduced into this rotation in
certain areas without adversely
impacting moisture or nutrient
accumulation (see Figure 1). Because
camelina has shallow roots with
drought resistant characteristics, the
10 See Shonnard, D. R., Williams, L., & Kalnes, T.
N. 2010. Camelina-Derived Jet Fuel and Diesel:
Sustainable Advanced Biodiesel. Environmental
Progress & Sustainable Energy, 382–392.
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land can be returned to wheat
cultivation the following year with
moisture and soil nutrients intact
quantitatively similar to a fallow year.11
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11 See
Shonnard et al., 2010; Lafferty et al., 2009.
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In addition, camelina uses the same
12 Wheeler, P and F. Guillen-Portal. 2007.
Camelina Production in Montana: A survey study
sponsored by Targeted Growth, Inc. and Barkley Ag.
Enterprises, LLP (unpublished).
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703
equipment for harvesting as wheat;
therefore, farmers would not need to
invest in new equipment to add
camelina to the rotation with wheat.12
BILLING CODE 6560–50–P
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BILLING CODE 6560–50–C
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b. Land Availability
USDA estimates that there are
approximately 60 million acres of wheat
in the U.S.13 USDA and wheat state
cooperative extension reports through
2008 indicate that 83% of U.S. wheat
production is under non-irrigated,
dryland conditions. Of the
approximately 50 million non-irrigated
acres, at least 45% are estimated to
follow a wheat/fallow rotation. Thus,
approximately 22 million acres are
potentially suitable for camelina
production. However, according to
industry projections, only about 9
million of these wheat/fallow acres have
the appropriate climate, soil profile, and
market access for camelina
production.14 Therefore, our analysis
uses the estimate that only 9 million
wheat/fallow acres are available for
camelina production.
c. Projected Volumes
Based on these projections of land
availability, EPA estimates that at
current yields (approximately 800
pounds per acre), approximately 100
million gallons (MG) of camelina-based
renewable fuels could be produced with
camelina grown in rotation with
existing crop acres without having
direct land use change impacts. Also,
since camelina will likely be grown on
fallow land and thus not displace any
other crop and since camelina currently
does not have other significant markets,
expanding production and use of
camelina for biofuel purposes is not
likely to have other agricultural market
impacts and therefore, would not result
in any significant indirect land use
impacts.15 This assessment is based on
a three year rotation cycle in which only
one third of the 9 million available acres
would be fallow in any given year.
Yields of camelina are expected to
approach the yields of similar oilseed
crops over the next few years, as
experience with growing camelina
improves cultivation practices and the
application of existing technologies are
more widely adopted.16 Yields of 1650
pounds per acre have been achieved on
test plots, and are in line with expected
yields of other oilseeds such as canola/
rapeseed. Assuming average US yields
of 1650 pounds per acre,17
approximately 200 MG of camelinabased renewable fuels could be
produced on existing wheat/fallow
acres. Finally, if investment in new seed
technology allows yields to increase to
levels assumed by Shonnard et al (3000
pounds per acre), approximately 400
MG of camelina-based renewable fuels
could be produced on existing acres.18
Depending on future crop yields, we
project that roughly 100 MG to 400 MG
of camelina-based biofuels could be
produced on currently fallow land with
no impacts on land use.19
705
d. Indirect Impacts
Although wheat can in some cases be
grown in rotation with other crops such
as lentils, flax, peas, garbanzo, and
millet, cost and benefit analysis indicate
that camelina is most likely to be
planted on soil with lower moisture and
nutrients where other rotation crops are
not viable.20 Because expected returns
on camelina are relatively uncertain,
farmers are not expected to grow
camelina on land that would otherwise
be used to grow cash crops with well
established prices and markets. Instead,
farmers are most likely to grow camelina
on land that would otherwise be left
fallow for a season. The opportunity
cost of growing camelina on this type of
land is much lower. As previously
discussed, this type of land represents
the 9 million acres currently being
targeted for camelina production.
Current returns on camelina are
relatively low ($13.24 per acre), given
average yields of approximately 800
pounds per acre and the current
contract price of $0.145 per pound.21
See Table 1. For comparison purposes,
the USDA projections for wheat returns
are between $88–$105 per acre between
2010 and 2020. Over time,
advancements in seed technology,
improvements in planting and
harvesting techniques, and higher input
usage could significantly increase future
camelina yields and returns.
TABLE 1—CAMELINA COSTS AND RETURNS
Rates
2010 Camelina 22
2022 Camelina 23
Herbicides:
Glysophate (Fall) .....................................
Glysophate (Spring) ................................
Post .........................................................
Seed:
Camelina seed ........................................
16 oz. ( $0.39/oz) ......
16 oz. ( $0.39/oz) ......
12 oz ( $0.67/oz) .......
$7.00 ..........................
$7.00 ..........................
$8.00 ..........................
$7.00 ..........................
$7.00 ..........................
$8.00 ..........................
$7.00.
$7.00.
$8.00.
$1.44/lb ......................
$5.76 ..........................
(4 lbs/acre) .................
$7.20 ..........................
(5 lbs/acre) .................
$7.20
(5 lbs/acre).
Fertilizer:
Nitrogen Fertilizer ....................................
$1/pd ..........................
Phosphate Fertilizer ................................
$1/pd ..........................
$25.00 ........................
(25 lb/acre) .................
$15.00 ........................
(15 lb/acre) .................
$40.00 ........................
(40 lb/acre) .................
$15.00 ........................
(15 lb/acre) .................
$75
(75 lbs/acre).
$15
(15 lb/acre).
Sub-Total .........................................
....................................
$67.76 ........................
$84.20 ........................
$119.20.
Logistics:
Planting Trip ............................................
Harvest & Hauling ...................................
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Inputs
....................................
....................................
$10.00 ........................
$25.00 ........................
$10.00 ........................
$25.00 ........................
$10.00.
$25.00.
13 2009 USDA Baseline. See https://
www.ers.usda.gov/publications/oce091/.
14 Johnson, S. and McCormick, M., Camelina: an
Annual Cover Crop Under 40 CFR Part 80 Subpart
M, Memorandum, dated November 5, 2010.
15 Wheeler, P. and Guillen-Portal F. 2007.
Camelina Production in Montana: A survey study
sponsored by Targeted Growth, Inc. and Barkley Ag.
Enterprises, LLP.
16 See Hunter, J and G. Roth. 2010. Camelina
Production and Potential in Pennsylvania, Penn
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State University Agronomy Facts 72. See https://
pubs.cas.psu.edu/freepubs/pdfs/uc212.pdf.
17 Ehrensing, D.T. and S.O. Guy. 2008. Oilseed
Crops—Camelina. Oregon State Univ. Ext. Serv.
EM8953–E. See https://extension.oregonstate.edu/
catalog/pdf/em/em8953-e.pdf; McVay & Lamb,
2008.
18 See Shonnard et al., 2010.
19 This assumes no significant adverse climate
impacts on world agricultural yields over the
analytical timeframe.
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2030 Camelina 24
20 See Lafferty et al., 2009; Shonnard et al., 2010;
Sustainable Oils Memo dated November 5, 2010,
21 Wheeler & Guillen-Portal, 2007.
22 See Sustainable Oils Memo dated November 5,
2010,
23 Based on yields technically feasible. See
McVey and Lamb, 2008; Ehrenson & Guy, 2008.
24 Adapted from Shonnard et al, 2010.
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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations
TABLE 1—CAMELINA COSTS AND RETURNS—Continued
Rates
2010 Camelina 22
2022 Camelina 23
Total Cost ........................................
....................................
$102.76 ......................
$119.20 ......................
$154.20.
Yields ..............................................................
Price ...............................................................
Total Revenue at avg prod/pricing .........
Returns ....................................................
lb/acre ........................
$/lb .............................
....................................
....................................
800 .............................
$0.145 ........................
$116.00 ......................
$13.24 ........................
1650 ...........................
$0.120 ........................
$198 ...........................
$78.80 ........................
3000.
$0.090.
$270.
$115.80.
Inputs
2030 Camelina 24
The determination in this final rule is
based on our projection that camelina is
likely to be produced on what would
otherwise be fallow land. However, the
rule applies to all camelina regardless of
where it is grown. EPA does not expect
that significant camelina would be
grown on non-fallow land, and small
quantities that may be grown elsewhere
and used for biofuel production will not
significantly impact our analysis.
Furthermore, although we expect
most camelina used as a feedstock for
renewable fuel production that would
qualify in the RFS program would be
grown in the U.S., today’s rule would
apply to qualifying renewable fuel made
from camelina grown in any country.
For the same reasons that pertain to U.S.
production of camelina, we expect that
camelina grown in other countries
would also be produced on land that
would otherwise be fallow and would
therefore have no significant land use
change impacts. The renewable biomass
provisions under the Energy
Independence and Security Act would
prohibit direct land conversion into new
agricultural land for camelina
production for biofuel internationally.
Additionally, any camelina production
on existing cropland internationally
would not be expected to have land use
impacts beyond what was considered
for international soybean production
(soybean oil is the expected major
feedstock source for U.S. biodiesel fuel
production and thus the feedstock of
reference for the camelina evaluation).
Because of these factors along with the
small amounts of fuel potentially
coming from other countries, we believe
that incorporating fuels produced in
other countries will not impact our
threshold analysis for camelina-based
biofuels.
Regarding crop inputs per acre, it
should be noted that camelina has a
higher percentage of oil per pound of
seed than soybeans. Soybeans are
approximately 18% oil, therefore
crushing one pound of soybeans yields
25 See Sustainable Oils Memo dated November 5,
2010 for a map of the regions of the country where
camelina is likely to be grown in wheat fallow
conditions.
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e. Crop Inputs
For comparison purposes, Table 2
shows the inputs required for camelina
production compared to the FASOM
agricultural input assumptions for
soybeans. Since yields and input
assumptions vary by region, a range of
values for soybean production are
shown in Table 2. The camelina input
values in Table 2 represent average
values, camelina input values will also
vary by region, however, less data is
available comparing actual practices by
region due to limited camelina
production. More information on
camelina inputs is available in materials
provided in the docket.
26 Wright
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While replacing the fallow period in
a wheat rotation is expected to be the
primary means by which the majority of
all domestic camelina is commercially
harvested in the short- to medium- term,
in the long term camelina may expand
to other regions and growing methods.25
For example, if camelina production
expanded beyond the 9 million acres
assumed available from wheat fallow
land, it could impact other crops.
However, as discussed above this is not
likely to happen in the near term due to
uncertainties in camelina financial
returns. Camelina production could also
occur in areas where wheat is not
commonly grown. For example, testing
of camelina production has occurred in
Florida in rotation with kanaf, peanuts,
cotton, and corn. However, only 200
acres of camelina were harvested in
2010 in Florida. While Florida acres of
camelina are expected to be higher in
2011, very little research has been done
on growing camelina in Florida. For
example, little is known about potential
seedling disease in Florida or how
camelina may be affected differently
than in colder climates.26 Therefore,
camelina grown outside of a wheat
fallow situation was not considered as
part of this analysis.
707
Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations
0.18 pounds of oil. In comparison,
camelina is approximately 36% oil,
therefore crushing one pound of
camelina yields 0.36 pounds of oil. The
difference in oil yield is taken into
account when calculating the emissions
per mmBTU included in Table 2. As
shown in Table 2, GHG emissions from
feedstock production for camelina and
soybeans are relatively similar when
factoring in variations in oil yields per
acre and fertilizer, herbicide, pesticide,
and petroleum use.
In summary, EPA concludes that the
agricultural inputs for growing camelina
are similar to those for growing soy
beans, direct land use impact is
expected to be negligible due to planting
on land that would be otherwise fallow,
and the limited production and use of
camelina indicates no expected impacts
on other crops and therefore no indirect
land use impacts.
f. Crushing and Oil Extraction
We also looked at the seed crushing
and oil extraction process and compared
the lifecycle GHG emissions from this
stage for soybean oil and camelina oil.
As discussed above, camelina seeds
produce more oil per pound than
soybeans. As a result, the lifecycle GHG
emissions associated with crushing and
oil extraction are lower for camelina
than soybeans, per pound of vegetable
oil produced. Table 3 summarizes data
on inputs, outputs and estimated
lifecycle GHG emissions from crushing
and oil extraction. The data on soybean
crushing comes from the RFS2 final
rule, based on a process model
developed by USDA–ARS.27 The data
on camelina crushing is from Shonnard
et al. (2010).
TABLE 3—COMPARISON OF CAMELINA AND SOYBEAN CRUSHING AND OIL EXTRACTION
Item
Soybeans
Material Inputs:
Beans or Seeds ..........................................................................................
Energy Inputs:
Electricity .....................................................................................................
Natural Gas & Steam .................................................................................
Outputs:
Refined vegetable oil ..................................................................................
Meal ............................................................................................................
GHG Emissions ..........................................................................................
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2. Feedstock Distribution, Fuel
Distribution, and Fuel Use
For this analysis, EPA projects that
the feedstock distribution emissions
will be the same for camelina and
soybean oil. To the extent that camelina
contains more oil per pound of seed, as
discussed above, the energy needed to
move the camelina would be lower than
soybeans per gallon of fuel produced.
To the extent that camelina is grown on
more disperse fallow land than soybean
and would need to be transported
further, the energy needed to move the
camelina could be higher than soybean.
Based on this, we believe the
assumption to use the same distribution
impacts for camelina as soybean is a
reasonable estimate of the GHG
emissions from camelina feedstock
distribution. In addition, the final fuel
produced from camelina is also
expected to be similar in composition to
the comparable fuel produced from
soybeans, therefore we are assuming
GHG emissions from the distribution
and use of fuels made from camelina
will be the same as emissions of fuel
produced from soybeans.
3. Fuel Production
There are two main fuel production
processes used to convert camelina oil
into fuel. The trans-esterification
process produces biodiesel and a
27 A. Pradhan, D.S. Shrestha, A. McAloon, W.
Yee, M. Haas, J.A. Duffield, H. Shapouri, September
2009, ‘‘Energy Life-Cycle Assessment of Soybean
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Camelina
5.38
Units
2.90
374
1,912
47
780
1.00
4.08
213
1.00
1.85
64
Lbs.
Btu.
Btu.
Lbs.
Lbs.
gCO2e/lb refined oil.
For this analysis, we assumed the
same biodiesel production facility
designs and conversion efficiencies as
modeled for biodiesel produced from
soybean oil and canola/rapeseed oil.
Camelina oil biodiesel is produced
using the same methods as soybean oil
biodiesel, therefore plant designs are
assumed to not significantly differ
between fuels made from these
feedstocks. As was the case for soybean
oil biodiesel, we have not projected in
our assessment of camelina oil biodiesel
any significant improvements in plant
technology. Unanticipated energy
saving improvements would further
improve GHG performance of the fuel
pathway.
The glycerin produced from camelina
biodiesel production is equivalent to the
glycerin produced from the existing
biodiesel pathways (e.g., based on soy
oil) that were analyzed as part of the
RFS2 final rule. Therefore the same coproduct credit would apply to glycerin
from camelina biodiesel as glycerin
produced in the biodiesel pathways
modeled for the RFS2 final rule. The
assumption is that the GHG reductions
associated with the replacement of
residual oil with glycerin on an energy
equivalent basis represents an
appropriate midrange co-product credit
of biodiesel produced glycerin.
As part of our RFS2 proposal, we
assumed the glycerin would have no
value and would effectively receive no
co-product credits in the soy biodiesel
pathway. We received numerous
comments, however, stating that the
glycerin would have a beneficial use
and should generate co-product
benefits. Therefore, the biodiesel
glycerin co-product determination made
as part of the RFS2 final rule took into
consideration the possible range of coproduct credit results. The actual coproduct benefit will be based on what
products are replaced by the glycerin
and what new uses develop for the coproduct glycerin. The total amount of
glycerin produced from the biodiesel
industry will actually be used across a
number of different markets with
different GHG impacts. This could
include for example, replacing
Biodiesel’’, United States Department of
Agriculture, Office of the Chief Economist, Office of
Energy Policy and New Uses, Agricultural
Economic Report Number 845.
glycerin co-product. The hydrotreating
process can be configured to produce
renewable diesel either primarily as
diesel fuel (including heating oil) or
primarily as jet fuel. Possible additional
products from hydrotreating include
naphtha, LPG, and propane. Both
processes and the fuels produced are
described in the following sections.
Both processes use camelina oil as a
feedstock and camelina crushing is also
included in the analysis.
a. Biodiesel
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petroleum glycerin, replacing fuel
products (residual oil, diesel fuel,
natural gas, etc.), or being used in new
products that don’t have a direct
replacement, but may nevertheless have
indirect effects on the extent to which
existing competing products are used.
The more immediate GHG reduction
credits from glycerin co-product use
will likely range from fairly high
reduction credits when petroleum
glycerin is replaced to lower reduction
credits if it is used in new markets that
have no direct replacement product, and
therefore no replaced emissions.
EPA does not have sufficient
information (and received no relevant
comments as part of the RFS2 rule) on
which to allocate glycerin use across the
range of likely uses. Therefore, EPA
believes that the approach used in RFS2
of picking a surrogate use for modeling
purposes in the mid-range of likely
glycerin uses, and the GHG emissions
results tied to such use, is reasonable.
The replacement of an energy
equivalent amount of residual oil is a
simplifying assumption determined by
EPA to reflect the mid-range of possible
glycerin uses in terms of GHG credits.
EPA believes that it is appropriately
representative of GHG reduction credit
across the possible range without
necessarily biasing the results toward
high or low GHG impact. Given the
fundamental difficulty of predicting
possible glycerin uses and impacts of
those uses many years into the future
under evolving market conditions, EPA
believes it is reasonable to use the more
simplified approach to calculating coproduct GHG benefit associated with
glycerin production.
Given the fact that GHG emissions
from camelina-based biodiesel would be
similar to the GHG emissions from
soybean- based biodiesel at all stages of
the lifecycle but would not result in
land use change as was the case for soy
oil used as a feedstock, we believe
biodiesel from camelina oil will also
meet the 50% GHG emissions reduction
threshold to qualify as a biomass based
diesel and an advanced fuel. Therefore,
EPA is including biodiesel produced
from camelina oil under the same
pathways for which biodiesel made
from soybean oil qualifies under the
RFS2 final rule.
b. Renewable Diesel (Including Jet Fuel
and Heating Oil), Naphtha, and LPG
The same feedstocks currently used
for biodiesel production can also be
used in a hydrotreating process to
produce a slate of products, including
diesel fuel, heating oil (defined as No.
1 or No. 2 diesel), jet fuel, naphtha, LPG,
and propane. Since the term renewable
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diesel is defined to include the products
diesel fuel, jet fuel and heating oil, the
following discussion uses the term
renewable diesel to also include diesel
fuel, jet fuel and heating oil. The yield
of renewable diesel is relatively
insensitive to feedstock source.28 While
any propane produced as part of the
hydrotreating process will most likely
be combusted within the facility for
process energy, the other co-products
that can be produced (i.e., renewable
diesel, naphtha, LPG) are higher value
products that could be used as
transportation fuels or, in the case of
naphtha, a blendstock for production of
transportation fuel. The hydrotreating
process maximized for producing a
diesel fuel replacement as the primary
fuel product requires more overall
material and energy inputs than
transesterification to produce biodiesel,
but it also results in a greater amount of
other valuable co-products as listed
above. The hydrotreating process can
also be maximized for jet fuel
production which requires even more
process energy than the process
optimized for producing a diesel fuel
replacement, and produces a greater
amount of co-products per barrel of
feedstock, especially naphtha.
Producers of renewable diesel from
camelina have expressed interest in
generating RINs under the RFS2
program for the slate of products
resulting from the hydrotreating
process. Our lifecycle analysis accounts
for the various uses of the co-products.
There are two main approaches to
accounting for the co-products
produced, the allocation approach, and
the displacement approach. In the
allocation approach all the emissions
from the hydrotreating process are
allocated across all the different coproducts. There are a number of ways to
do this but since the main use of the coproducts would be to generate RINs as
a fuel product we allocate based on the
energy content of the co-products
produced. In this case, emissions from
the process would be allocated equally
to all the Btus produced. Therefore, on
a per Btu basis all co-products would
have the same emissions. The
displacement approach would attribute
all of the emissions of the hydrotreating
process to one main product and then
account for the emission reductions
from the other co-products displacing
alternative product production. For
example, if the hydrotreating process is
28 Kalnes, T., N., McCall, M., M., Shonnard, D.,
R., 2010. Renewable Diesel and Jet-Fuel Production
from Fats and Oils. Thermochemical Conversion of
Biomass to Liquid Fuels and Chemicals, Chapter 18,
p. 475.
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configured to maximize diesel fuel
replacement production, all of the
emissions from the process would be
attributed to diesel fuel, but we would
then assume the other co-products were
displacing alternative products, for
example, naphtha would displace
gasoline, LPG would displace natural
gas, etc. This assumes the other
alternative products are not produced or
used, so we would subtract the
emissions of gasoline production and
use, natural gas production and use, etc.
This would show up as a GHG emission
credit associated with the production of
diesel fuel replacement.
To account for the case where RINs
are generated for the jet fuel, naphtha
and LPG in addition to the diesel
replacement fuel produced, we would
not give the diesel replacement fuel a
displacement credit for these coproducts. Instead, the lifecycle GHG
emissions from the fuel production
processes would be allocated to each of
the RIN-generating products on an
energy content basis. This has the effect
of tending to increase the fuel
production lifecycle GHG emissions
associated with the diesel replacement
fuel because there are less co-product
displacement credits to assign than
would be the case if RINs were not
generated for the co-products.29 On the
other hand, the upstream lifecycle GHG
emissions associated with producing
and transporting the plant oil feedstocks
will be distributed over a larger group
of RIN-generating products. Assuming
each product (except propane) produced
via the camelina oil hydrotreating
process will generate RINs results in
higher lifecycle GHG emissions for
diesel fuel replacement as compared to
the case where the co-products are not
used to generate RINs. This general
principle is also true when the
hydrotreating process is maximized for
jet fuel production. As a result, the
worst GHG performance (i.e., greatest
lifecycle GHG emissions) for diesel
replacement fuel and jet fuel produced
from camelina oil via hydrotreating will
occur when all of the co-products are
RIN-generating (we assume propane will
be used for process energy). Thus, if
these fuels meet the 50% GHG
reduction threshold for biomass based
diesel or advanced biofuel when coproducts are RIN-generating, they will
29 For a similar discussion see page 46 of Stratton,
R.W., Wong, H.M., Hileman, J.I. 2010. Lifecycle
Greenhouse Gas Emissions from Alternative Jet
Fuels. PARTNER Project 28 report. Version 1.1.
PARTNER–COE–2010–001. June 2010, https://
web.mit.edu/aeroastro/partner/reports/proj28/
partner-proj28–2010–001.pdf.
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evaluation considers information
published in peer-reviewed journal
articles and publicly available literature
(Kalnes et al, 2010, Pearlson, M., N.,
2011,30 Stratton et al., 2010, Huo et al.,
2008).31 Our analysis of GHG emissions
from the hydrotreating process is based
also do so in the case when RINs are not
generated for co-products.
We have evaluated information about
the lifecycle GHG emissions associated
with the hydrotreating process which
can be maximized for jet fuel or diesel
replacement fuel production. Our
on the mass and energy balance data in
Pearlson (2011) which analyzes a
hydrotreating process maximized for
diesel replacement fuel production and
a hydrotreating process maximized for
jet fuel production.32 This data is
summarized in Table 4.
TABLE 4—HYDROTREATING PROCESSES TO CONVERT CAMELINA OIL INTO DIESEL REPLACEMENT FUEL AND JET FUEL33
Maximized for
diesel fuel
production
Inputs:
Refined camelina oil ..............................................................................................
Hydrogen ...............................................................................................................
Electricity ...............................................................................................................
Natural Gas ...........................................................................................................
Outputs:
Diesel Fuel .............................................................................................................
Jet fuel ...................................................................................................................
Naphtha .................................................................................................................
LPG ........................................................................................................................
Propane .................................................................................................................
Table 5 compares lifecycle GHG
emissions from oil extraction and fuel
production for soybean oil biodiesel and
for camelina-based diesel and jet fuel.
The lifecycle GHG estimates for
camelina oil diesel and jet fuel are based
on the input/output data summarized in
Table 3 (for oil extraction) and Table 4
(for fuel production). We assume that
the propane co-product does not
generate RINs; instead, it is used for
process energy displacing natural gas.
Maximized for jet
fuel production
9.56
0.04
652
23,247
12.84
0.08
865
38,519
123,136
23,197
3,306
3,084
7,454
We also assume that the naphtha is used
as blendstock for production of
transportation fuel to generate RINs. In
this case we assume that RINs are
generated for the use of LPG in a way
that meets the EISA definition of
transportation fuel, for example it could
be used in a nonroad vehicle. The
lifecycle GHG results in Table 5
represent the worst case scenario (i.e.,
highest GHG emissions) because all of
the eligible co-products are used to
55,845
118,669
17,042
15,528
9,881
Units (per gallon
of fuel
produced)
Lbs.
Lbs.
Btu.
Btu.
Btu.
Btu.
Btu.
Btu.
Btu.
generate RINs. This is because, as
discussed above, lifecycle GHG
emissions per Btu of diesel or jet fuel
would be lower if the naphtha or LPG
is not used to generate RINs and is
instead used for process energy
displacing fossil fuel such as natural
gas. Supporting information for the
values in Table 5, including key
assumptions and data, is provided
through the docket.
TABLE 5—FUEL PRODUCTION LIFECYCLE GHG EMISSIONS (KGCO2e/MMBTU) 34
Feedstock
Production process
RIN–Generating
products
Other co-products
Soybean Oil .............
Camelina Oil ............
Camelina Oil ............
Trans-Esterification
Trans-Esterification
Hydrotreating Maximized for Diesel.
Biodiesel .................
Biodiesel .................
Diesel .....................
Jet Fuel.
Naphtha.
LPG.
Glycerin ..................
Glycerin ..................
Propane ..................
14
4
4
(1)
(1)
8
13
3
12
Camelina Oil ............
Hydrotreating Maxi- Jet Fuel ..................
mized for Jet Fuel. Diesel.
Naphtha.
LPG.
Propane ..................
4
11
14
Oil extraction
Processing
Total
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As discussed above, for a process that
produces more than one RIN-generating
output (e.g., the hydrotreating process
summarized in Table 5 which produces
diesel replacement fuel, jet fuel, and
naphtha) we allocate lifecycle GHG
emissions to the RIN generating
products on an energy equivalent basis.
We then normalize the allocated
lifecycle GHG emissions per mmBtu of
each fuel product. Therefore, each RINgenerating product from the same
process will be assigned equal lifecycle
GHG emissions per mmBtu from fuel
processing. For example, based on the
30 Pearlson, M., N. 2011. A Techno-Economic and
Environmental Assessment of Hydroprocessed
Renewable Distillate Fuels.
31 Huo, H., Wang., M., Bloyd, C., Putsche, V.,
2008. Life-Cycle Assessment of Energy and
Greenhouse Gas Effects of Soybean-Derived
Biodiesel and Renewable Fuels. Argonne National
Laboratory. Energy Systems Division. ANL/ESD/08–
2. March 12, 2008.
32 We have also considered data submitted by
companies involved in the hydrotreating industry
which is claimed as confidential business
information (CBI). The conclusions using the CBI
data are consistent with the analysis presented here.
33 Based on Pearlson (2011), Table 3.1 and Table
3.2.
34 Lifecycle GHG emissions are normalized per
mmBtu of RIN-generating fuel produced. Totals
may not be the sum of the rows due to rounding
error. Parentheses indicate negative numbers.
Process emissions for biodiesel production are
negative because they include the glycerin offset
credit.
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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations
lifecycle GHG estimates in Table 5 for
the hydrotreating process maximized to
produce jet fuel, the jet fuel and the
naphtha both have lifecycle GHG
emissions of 14 kgCO2e/mmBtu. For the
same reasons, the lifecycle GHG
emissions from the jet fuel and naphtha
will stay equivalent if we consider
upstream GHG emissions, such as
emissions associated with camelina
cultivation and harvesting. Lifecycle
GHG emissions from fuel distribution
and use could be somewhat different for
the jet fuel and naphtha, but since these
stages produce a relatively small share
of the emissions related to the full fuel
lifecycle, the overall difference will be
quite small.
Given that GHG emissions from
camelina oil would be similar to the
GHG emissions from soybean oil at all
stages of the lifecycle but would not
result in land use change emissions (soy
oil feedstock did have a significant land
use change impact but still met a 50%
GHG reduction threshold), and
considering differences in process
emissions between soybean biodiesel
and camelina-based renewable diesel,
we conclude that renewable diesel from
camelina oil will also meet the 50%
GHG emissions reduction threshold to
qualify as biomass based diesel and
advanced fuel. Although some of the
potential configurations result in fuel
production GHG emissions that are
higher than fuel production GHG
emissions for soybean oil biodiesel, land
use change emissions account for
approximately 80% of the soybean oil to
biodiesel lifecycle GHGs. Since
camelina is assumed not to have land
use change emissions, our analysis
shows that camelina renewable diesel
will qualify for advanced renewable fuel
and biomass-based diesel RINs even for
the cases with the highest lifecycle
GHGs (e.g., when all of the co-products
are used to generate RINs.) Because the
lifecycle GHG emissions for RINgenerating co-products are very similar,
we can also conclude naphtha and LPG
produced from camelina oil will also
meet the 50% GHG emissions reduction
threshold. If the facility does not
actually generate RINs for one or more
of these co-products, we estimate that
the lifecycle GHG emissions related to
the RIN-generating products would be
lower, thus renewable diesel (which
includes diesel fuel, jet fuel, and heating
oil) from camelina would still meet the
50% emission reduction threshold.
4. Summary
Current information suggests that
camelina has limited niche markets and
will be produced on land that would
otherwise remain fallow. Therefore,
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increased production of camelina-based
renewable fuel is not expected to result
in significant land use change
emissions. For the purposes of this
analysis, EPA is projecting there will be
no land use emissions associated with
camelina production for use as a
renewable fuel feedstock.
However, while production of
camelina on acres that would otherwise
remain fallow is expected to be the
primary means by which the majority of
all camelina is commercially harvested
in the short- to medium- term, in the
long term camelina may expand to other
growing methods and lands if demand
increases substantially beyond what
EPA is currently predicting. While the
impacts are uncertain, there are some
indications demand could increase
significantly. For example, camelina is
included under USDA’s Biomass Crop
Assistance Program (BCAP) and there is
growing support for the use of camelina
oil in producing drop-in alternative
aviation fuels. EPA plans to monitor the
expansion of camelina production to
verify whether camelina is primarily
grown on existing acres once camelina
is produced at larger-scale volumes.
Similarly, we will consider market
impacts if alternative uses for camelina
expand significantly beyond what was
described in the above analysis. Just as
EPA plans to periodically review and
revise the methodology and
assumptions associated with calculating
the GHG emissions from all renewable
fuel feedstocks, EPA expects to review
and revise as necessary the analysis of
camelina in the future.
Taking into account the assumption of
no land use change emissions when
camelina is used to produce renewable
fuel, and considering that other sources
of GHG emissions related to camelina
biodiesel or renewable diesel
production have comparable GHG
emissions to biodiesel from soybean oil,
we have determined that camelinabased biodiesel and renewable diesel
should be treated in the same manner as
soy-based biodiesel and renewable
diesel in qualifying as biomass-based
diesel and advanced biofuel for
purposes of RIN generation, since the
GHG emission performance of the
camelina-based fuels will be at least as
good and in some respects better than
that modeled for fuels made from
soybean oil. EPA found as part of the
Renewable Fuel Standard final
rulemaking that soybean biodiesel
resulted in a 57% reduction in GHG
emissions compared to the baseline
petroleum diesel fuel. Furthermore,
approximately 80% of the lifecycle
impacts from soybean biodiesel were
from land use change emissions which
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are assumed to be not significant for the
camelina pathway considered. Thus,
EPA is including camelina oil as a
potential feedstock under the same
biodiesel and renewable diesel (which
includes diesel fuel, jet fuel, and heating
oil) pathways for which soybean oil
currently qualifies. We are also
including a pathway for naphtha and
LPG produced from camelina oil
through hydrotreating. This is based on
the fact that our analysis shows that
even when all of the co-products are
used to generate RINs the lifecycle GHG
emissions for RIN-generating coproducts including diesel replacement
fuel, jet fuel, naphtha and LPG
produced from camelina oil will all
meet the 50% GHG emissions reduction
threshold.
We are also clarifying that two
existing pathways for RIN generation in
the RFS regulations that list ‘‘renewable
diesel’’ as a fuel product produced
through a hydrotreating process include
jet fuel. This applies to two pathways in
Table 1 to § 80.1426 of the RFS
regulations which both list renewable
diesel made from soy bean oil, oil from
annual covercrops, algal oil, biogenic
waste oils/fats/greases, or non-food
grade corn oil using hydrotreating as a
process. If parties produce jet fuel from
the hydrotreating process and coprocess renewable biomass and
petroleum they can generate advanced
biofuel RINs (D code 5) for the jet fuel
produced. If they do not co-process
renewable biomass and petroleum they
can generate biomass-based diesel RINs
(D code 4) for the jet fuel produced.
§ 80.1401 of the RFS regulations
currently defines non-ester renewable
diesel as a fuel that is not a mono-alkyl
ester and which can be used in an
engine designed to operate on
conventional diesel fuel or be heating
oil or jet fuel. The reference to jet fuel
in this definition was added by direct
final rule dated May 10, 2010. Table 1
to § 80.1426 identifies approved fuel
pathways by fuel type, feedstock source
and fuel production processes. The
table, which was largely adopted as part
of the March 26, 2010 RFS2 final rule,
identifies jet fuel and renewable diesel
as separate fuel types. Accordingly, in
light of the revised definition of
renewable diesel enacted after the RFS2
rule, there is ambiguity regarding the
extent to which references in Table 1 to
‘‘renewable diesel’’ include jet fuel.
The original lifecycle analysis for the
renewable diesel from hydrotreating
pathways listed in Table 1 to § 80.1426
was not based on producing jet fuel but
rather other transportation diesel fuel
products, namely a diesel fuel
replacement. As discussed above, the
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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations
hydrotreating process can produce a
mix of products including jet fuel,
diesel, naphtha, LPG and propane. Also,
as discussed, there are differences in the
process configured for maximum jet fuel
production vs. the process maximized
for diesel fuel production and the
lifecycle results vary depending on what
approach is used to consider coproducts (i.e., the allocation or
displacement approach).
In cases where there are no pathways
for generating RINs for the co-products
from the hydrotreating process it would
be appropriate to use the displacement
method for capturing the credits of coproducts produced. This is the case for
most of the original feedstocks included
in Table 1 to § 80.1426.35 As was
discussed previously, if the
displacement approach is used when jet
fuel is the primary product produced it
results in lower emissions then the
production maximized for diesel fuel
production. Therefore, since the
hydrotreating process maximized for
diesel fuel meets the 50% lifecycle GHG
threshold for the feedstocks in question,
the process maximized for jet fuel
would also qualify.
Thus, we are interpreting the
references to ‘‘renewable diesel’’ in
Table 1 to include jet fuel, consistent
with our regulatory definition of ‘‘nonester renewable diesel,’’ since doing so
clarifies the existing regulations while
ensuring that Table 1 to § 80.1426
appropriately identifies fuel pathways
that meet the GHG reduction thresholds
associated with each pathway.
We note that although the definition
of renewable diesel includes jet fuel and
heating oil, we have also listed in Table
1 of section 80.1426 of the RFS2
regulations jet fuel and heating oil as
specific co-products in addition to
listing renewable diesel to assure
clarity. This clarification also pertains to
all the feedstocks already included in
Table 1 for renewable diesel.
mstockstill on DSK4VPTVN1PROD with RULES3
B. Lifecycle Greenhouse Gas Emissions
Analysis for Ethanol, Diesel, Jet Fuel,
Heating Oil, and Naphtha Produced
From Energy Cane, Giant Reed, and
Napiergrass
For this rulemaking, EPA considered
the lifecycle GHG impacts of three new
types of high-yielding perennial grasses
similar in cellulosic composition to
switchgrass and comparable in status as
an emerging energy crop. Energy cane
(related to sugarcane), giant reed
(Arundo donax), and napiergrass
35 The exception is naphtha produced from waste
categories, but these would pass the lifecycle
thresholds regardless of the allocation approach
used given their low feedstock GHG impacts.
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(pennisetum purpureum), also known as
elephant grass. In the proposed and
final RFS2 rule, EPA analyzed the
lifecycle GHG impacts of producing and
using cellulosic ethanol and cellulosic
Fischer-Tropsch diesel from
switchgrass. The midpoint of the range
of switchgrass results showed a 110%
GHG reduction (range of 102%–117%)
for cellulosic ethanol (biochemical
process), a 72% (range of ¥64% to
¥79%) reduction for cellulosic ethanol
(thermochemical process), and a 71%
(range of ¥62% to ¥77%) reduction for
cellulosic diesel (F–T process)
compared to the petroleum baseline. In
the RFS2 final rule, we indicated that
some feedstock sources can be
determined to be similar enough to
those modeled that the modeled results
could reasonably be extended to these
similar feedstock types. For instance,
information on miscanthus indicated
that this perennial grass will yield more
feedstock per acre than the modeled
switchgrass feedstock without
additional inputs with GHG
implications (such as fertilizer).
Therefore in the final rule EPA
concluded that since biofuel made from
the cellulosic biomass in switchgrass
was found to satisfy the 60% GHG
reduction threshold for cellulosic
biofuel, biofuel produced form the
cellulosic biomass in miscanthus would
also comply. In the final rule we
included cellulosic biomass from
switchgrass and miscanthus as eligible
feedstocks for the cellulosic biofuel
pathways included in Table 1 to
§ 80.1426.
We did not include other perennial
grasses such as energy cane, giant reed,
or napiergrass as feedstocks for the
cellulosic biofuel pathways in Table 1 at
that time, since we did not have
sufficient time to adequately consider
them. Based in part on additional
information received through the
petition process for EPA approval of
energy cane, giant reed, and napiergrass
pathways, EPA has evaluated these
feedstocks and is now including the
cellulose, hemicelluloses and lignin
portions of renewable biomass from
energy cane, giant reed, and napiergrass
in Table 1 to § 80.1426 as approved
feedstocks for cellulosic biofuel
pathways.
As described in detail in the following
sections of this preamble, because of the
similarity of these feedstocks to
switchgrass and miscanthus, EPA
believes that new agricultural sector
modeling is not needed to analyze them.
We have instead relied upon the
switchgrass analysis to assess the
relative GHG impacts of biofuel
produced from energy cane, giant reed,
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711
and napiergrass. As with the
switchgrass analysis, we have attributed
all land use impacts and resource inputs
from use of these feedstocks to the
portion of the fuel produced that is
derived from the cellulosic components
of the feedstocks. Based on this analysis
and currently available information, we
conclude that biofuel (ethanol,
cellulosic diesel, jet fuel, heating oil and
naptha) produced from the cellulosic
biomass of energy cane, giant reed, or
napiergrass has similar lifecycle GHG
impacts to switchgrass biofuel and
meets the 60% GHG reduction threshold
required for cellulosic biofuel.
1. Feedstock Production and
Distribution
For the purposes of this rulemaking,
energy cane refers to varieties of
perennial grasses in the Saccharum
genus which are intentionally bred for
high cellulosic biomass productivity but
have characteristically low sugar
content making them unsuitable as a
primary source of sugar as compared to
other varieties of grasses commonly
known as ‘‘sugarcane’’ in the
Saccharum genus. Energy cane varieties
developed to date have low tolerance for
cold temperatures but grow well in
warm, humid climates. Energy cane
originated from efforts to improve
disease resistance and hardiness of
commercial sugarcane by crossbreeding
commercial and wild sugarcane strains.
Certain higher fiber, lower sugar
varieties that resulted were not suitable
for commercial sugar production, and
are now being developed as a highbiomass energy crop. There is currently
no commercial production of energy
cane. Current plantings are mainly
limited to research field trials and small
demonstrations for bioenergy purposes.
However, based in part on discussions
with industry, EPA anticipates
continued development of energy cane
particularly in the south-central and
southeastern United States due to its
high yields in these regions.
Giant reed refers to the perennial
grass Arundo donax of the Gramineae
family. Giant reed thrives in subtropical
and warm-temperate areas and is grown
throughout Asia, southern Europe,
Africa, the Middle East, and warmer
U.S. states for multiple uses such as
paper and pulp, musical instruments,
rayon, particle boards, erosion control,
and ornamental purposes.36 37 Based in
36 See https://www.fs.fed.us/database/feis/plants/
graminoid/arudon/all.html.
37 See Lewandowski, I., Scurlock, J.M.O.,
Lindvall, E., Christou, M. (2003). The development
and current status of perennial rhizomatous grasses
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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations
part on discussions with industry, EPA
anticipates continued development of
giant reed as an energy crop particularly
in the Mediterranean region and warmer
U.S. states.
Napiergrass is a tall bunch-type grass
that has traditionally been grown as a
high-yielding forage crop across the wet
tropics. There is a considerable body of
agronomic research on the production of
napiergrass as a forage crop. More
recently, researchers have investigated
ways to maximize traits desirable in
bioenergy crops. Practices have been
developed by USDA and other
researchers to lower fertilization rates
and increase biomass production. Based
in part on discussions with industry,
EPA anticipates continued development
of napiergrass as an energy crop
particularly in Gulf Coast Region of the
United States (more specifically the
growing region includes Florida and
southern portions of Texas, Louisiana,
Georgia, Alabama and Mississippi).38
a. Crop Yields
mstockstill on DSK4VPTVN1PROD with RULES3
For the purposes of analyzing the
GHG emissions from energy cane, giant
reed, and napiergrass production, EPA
examined crop yields and production
inputs in relation to switchgrass to
assess the relative GHG impacts. Current
national yields for switchgrass are
approximately 4.5 to 5 dry tons per acre.
Average energy cane yields exceed
switchgrass yields in both unfertilized
and fertilized trails conducted in the
southern United States. Unfertilized
yields are around 7.3 dry tons per acre
while fertilized trials show energy cane
yields range from approximately 11 to
20 dry tons per acre.39 40 Until recently
there have been few efforts to improve
energy cane yields, but several energy
cane development programs are now
underway to further increase its biomass
productivity. Giant reed field trials
conducted in Alabama over a 9-year
period showed an average yield of 15
dry tons per acre with no nitrogen
fertilizer applied after the first year.41
as energy crops in the US and Europe. Biomass and
Bioenergy 25, 335–361.
38 For a map depicting the northern limit for
sustained napiergrass production in the United
States see Figure 1 in Woodard, K., R. and
Sollenberger, L, E. 2008. Production of Biofuel
Crops in Florida: Elephantgrass. Institute of Food
and Agricultural Sciences, University of Florida. SS
AGR 297.
39 See Bischoff, K.P., Gravois, K.A., Reagan, T.E.,
Hoy, J.W., Kimbeng, C.A., LaBorde, C.M., Hawkins,
G.L. Plant Regis. 2008, 2, 211–217.
40 See Hale, A.L. Sugar Bulletin, 2010, 88, 28–29.
41 Huang, P., Bransby, D., and Sladden, S. (2010).
Exceptionally high yields and soil carbon
sequestration recorded for giant reed in Alabama.
Poster session presented at: ASA, CSSA, and SSSA
2010 International Annual Meetings, Green
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Fertilized field trials have shown yields
around 13 to 28 dry tons per acre in
Spain, and 12 dry tons per acre in Italy
(based on annual yields of 3, 14, 17, 16,
and 12).42 High yields have been
demonstrated with unimproved giant
reed populations, and therefore there is
potential for increased biomass
productivity through improved growing
methods and breeding efforts.43
Napiergrass field trials have produced
dry biomass yields exceeding 20 tons
per acre per year in north-central
Florida. Using currently available
technology, average yields for fullseason napiergrass should range from 14
to 18 tons per acre with future
improvements expected. Yield depends
greatly on the type of cultivar and the
amount and distribution of rainfall and
fertilization rates. There is potential for
increased biomass productivity through
improved growing methods and
breeding efforts.44 In general, the yields
for all three of the energy grasses
considered here will have higher yields
than switchgrass, so from a crop yield
perspective, the switchgrass analysis
would be a conservative estimate when
comparing against the energy cane,
napier grass, and giant reed pathways.
Furthermore, EPA’s analysis of
switchgrass for the RFS2 rulemaking
assumed a 2% annual increase in yield
that would result in an average national
yield of 6.6 dry tons per acre in 2022.
EPA anticipates a similar yield
improvement for energy cane, giant
reed, and napiergrass due to their
similarity as perennial grasses and their
comparable status as energy crops in
their early stages of development. Given
this, our analysis assumes an average
energy cane yield of 19 dry tons per acre
in the southern United States by 2022;
an average giant reed yield of
approximately 18 dry tons per acre by
2022; and an average napiergrass yield
of approximately 20 dry tons per acre by
2022.45 The ethanol yield for all of the
grasses is approximately the same so the
higher crop yields for energy cane,
napiergrass, and giant reed result
directly in greater ethanol production
compared to switchgrass per acre of
production.
Revolution 2.0; 2010 Oct 31–Nov 4; Long Beach,
CA.
42 Mantineo, M., D’Agnosta, G.M., Copani, V.,
`
Patane, C., and Cosentino, S.L. (2009). Biomass
yield and energy balance of three perennial crops
for energy use in the semi-arid Mediterranean
environment. Field Crops Research 114, 204–213.
43 Lewandowski et al. 2003.
44 Based on discussions with industry and USDA
and Woodard and Sollenberger (2008).
45 These yields assume no significant adverse
climate impacts on world agricultural yields over
the analytical timeframe.
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Based on these yield assumptions, in
areas with suitable growing conditions,
energy cane would require
approximately 26% to 47% of the land
area required by switchgrass to produce
the same amount of biomass, giant reed
would require less than 40% of the land
area required by switchgrass to produce
the same amount of biomass, and
napiergrass would require
approximately 33% of the land area
required by switchgrass to produce the
same amount of biomass due to their
higher yields. Even without yield
growth assumptions, their currently
higher crop yield rates means the land
use required for these crops would be
lower than for switchgrass. Therefore
less crop area would be converted and
displaced resulting in smaller land-use
change GHG impacts than that assumed
for switchgrass to produce the same
amount of fuel. Furthermore, we believe
energy cane and napiergrass will have a
similar impact on international markets
as assumed for switchgrass. Like
switchgrass, energy cane and
napiergrass are not expected to be
traded internationally and their impacts
on other crops are expected to be
limited. Increased giant reed demand in
the U.S. for biofuels is not expected to
impact existing markets for giant reed,
which are relatively small niche markets
(e.g., musical instrument reeds).
b. Land Use
In EPA’s RFS2 analysis, switchgrass
plantings displaced primarily soybeans
and wheat, and to a lesser extent hay,
rice, sorghum, and cotton. Energy cane
and napiergrass, with production
focused in the southern United States,
are likely to be grown on land once used
for pasture, rice, commercial sod, cotton
or alfalfa, which would likely have less
of an international indirect impact than
switchgrass because some of those
commodities are not as widely traded as
soybeans or wheat. Given that energy
cane and napiergrass will likely
displace the least productive land first,
EPA concludes that the land use GHG
impact for energy cane and napiergrass
per gallon should be no greater and
likely less than estimated for
switchgrass. Given that giant reed is in
early stages of development as an energy
crop, there is limited information on
where it will be grown and what crops
it will displace. We expect giant reed
will displace the least productive land
first and would likely have a similar or
smaller indirect impact associated with
crop displacement than what we
assumed for switchgrass.
Considering the total land potentially
impacted by all the new feedstocks
included in this rulemaking would not
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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations
impact these conclusions (including the
camelina discussed in the previous
section and the three energy grasses
considered here). As discussed
previously, the camelina is expected to
be grown on fallow land in the
Northwest, while energy grasses are
expected to be grown mainly in the
south on existing cropland or
pastureland. In the switchgrass ethanol
scenario done for the Renewable Fuel
Standard final rulemaking, total
cropland acres increases by 4.2 million
acres, including an increase of 12.5
million acres of switchgrass, a decrease
of 4.3 million acres of soybeans, a 1.4
million acre decrease of wheat acres, a
decrease of 1 million acres of hay, as
well as decreases in a variety of other
crops. Given the higher yields of the
energy grasses considered here
compared to switchgrass, there would
be ample land available for production
without having any adverse impacts
beyond what was considered for
switchgrass production.
c. Crop Inputs and Feedstock Transport
EPA also assessed the GHG impacts
associated with planting, harvesting,
and transporting energy cane, giant
reed, and napiergrass feedstocks in
comparison to switchgrass. Table 6
shows the assumed 2022 commercialscale production inputs for switchgrass
(used in the RFS2 rulemaking analysis),
average energy cane, giant reed, and
napiergrass production inputs (USDA
projections and industry data) and the
associated GHG emissions.
Available data gathered by EPA
suggest that energy cane requires on
average less nitrogen, phosphorous,
potassium, and pesticide than
switchgrass per dry ton of biomass, but
more herbicide, lime, diesel, and
electricity per unit of biomass. Giant
reed may require on average less
nitrogen and insecticide than
switchgrass, but more phosphorous,
potassium, herbicide, diesel, and
electricity per unit of biomass.
Napiergrass may require similar
amounts of nitrogen fertilizer
application as switchgrass, less
phosphorous, potassium and insecticide
than switchgrass, but more herbicide,
lime, diesel, and electricity per unit of
biomass.
This assessment assumes production
of all three new feedstocks uses
electricity for irrigation given that
growers will likely irrigate when
possible to improve yields. Irrigation
rates will vary depending on the timing
and amount of rainfall, but for the
purpose of estimating GHG impacts of
electricity use for irrigation, we
assumed a rate similar to what we
assumed for other irrigated crops in the
Southwest, South Central, and
Southeast as shown in Table 6.
Applying the GHG emission factors
used in the RFS2 final rule, energy cane
production results in slightly higher
GHG emissions relative to switchgrass
production (an increase of
approximately 4 kg CO2eq/mmbtu).
Giant reed production results in slightly
lower GHG emissions relative to
switchgrass production (a decrease of
approximately 2 kg CO2eq/mmbtu).
Napiergrass production results in
slightly higher GHG emissions relative
to switchgrass production (an increase
of approximately 6 kg CO2eq/mmbtu).
TABLE 6—PRODUCTION INPUTS AND GHG EMISSIONS FOR SWITCHGRASS, ENERGY CANE, GIANT REED, AND
NAPIERGRASS (BIOCHEMICAL ETHANOL), 2022
Switchgrass
Emission factors
Nitrogen Fertilizer
N2O .....................
Phosphorus Fertilizer.
Potassium Fertilizer.
Herbicide .............
Insecticide (average across regions).
Lime ....................
Diesel ..................
Electricity (irrigation).
Total Emissions.
Inputs (per
dry ton of
biomass)
3,29 kgCO2e/ton
of nitrogen.
N/A ......................
1,12 kgCO2e/ton
of phosphate.
743 kgCO2e/ton
of potassium.
23,45 kgCO2e/
tons of herbicide.
27,22 kgCO2e/
tons of pesticide.
408 kgCO2e/ton
of lime.
97 kgCO2e/
mmBtu diesel.
220 kgCO2e/
mmBtu.
.............................
Energy Cane
Emissions (per
mmBtu fuel)
Inputs (per
dry ton of
biomass)
15.2 lbs ....
3.6 kgCO2e ....
N/A ...........
6.1 lbs ......
Giant Reed
Emissions (per
mmBtu fuel)
Inputs (per
dry ton of
biomass)
8.4 lbs ......
2 kgCO2e .......
7.6 kgCO2e ....
0.5 kgCO2e ....
N/A ...........
3.2 lbs ......
6.1 lbs ......
0.3 kgCO2e ....
0.002 lbs ..
Napiergrass
Emissions (per
mmBtu fuel)
Inputs (per
dry ton of
biomass)
Emissions (per
mmBtu fuel)
5 lbs .........
1 kgCO2e .......
10 lbs .......
2.4 kgCO2e.
5.9 kgCO2e ....
0.3 kgCO2e ....
N/A ...........
7.4 lbs ......
4.8 kgCO2e ....
0.6 kgCO2e ....
N/A ...........
1.1 lbs ......
7.6 kgCO2e.
0.1 kgCO2e.
4.2 lbs ......
0.2 kgCO2e ....
7.4 lbs ......
0.4 kgCO2e ....
4.0 lbs ......
0.2 kgCO2e.
0.003 kgCO2e
1.0 lbs ......
1.8 kgCO2e ....
0.02 lbs ....
0.03 kgCO2e ..
0.4 lbs ......
0.6 kgCO2e.
0.025 lbs ..
0.04 kgCO2e ..
0 lbs .........
0 kgCO2e .......
0 lbs .........
0 kgCO2e .......
0 lbs .........
0 kgCO2e.
0 lbs .........
0 kgCO2e .......
104.7 lbs ..
3.1 kgCO2e ....
0 lbs .........
0 kgCO2e .......
100 lbs .....
2.9 kgCO2e.
0.4 gal ......
0.8 kgCO2e ....
1.3 gal ......
2.4 kgCO2e ....
1.4 gal ......
2.5 kgCO2e ....
1.3 gal ......
2.2 kgCO2e.
0 kWh .......
0 kgCO2e .......
14.7 kWh ..
1.6 kgCO2e ....
10 kWh .....
1 kgCO2e .......
25 kWh .....
2.7 kgCO2e.
..................
13 kgCO2e/
mmBtu.
..................
17 kgCO2e/
mmBtu.
..................
11 kgCO2e/
mmBtu.
..................
19 kgCO2e/
mmBtu.
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Assumes 2022 switchgrass yield of 6.59 dry tons/acre and 92.3 gal ethanol/dry ton, 2022 energy cane yield of 19.1 dry tons/acre and 92 gal ethanol/dry ton, 2022
giant reed yield of 18 dry tons/acre and 92.3 gal ethanol/dry ton, and 2022 napiergrass yield of 20 dry tons/acre and 92.3 gal ethanol/dry ton. More detail on calculations and assumptions is included in materials to the docket.
GHG emissions associated with
distributing energy cane, giant reed, and
napiergrass feedstocks are expected to
be similar to EPA’s estimates for
switchgrass feedstock because they are
all herbaceous agricultural crops
requiring similar transport, loading,
unloading, and storage regimes. Our
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analysis therefore assumes the same
GHG impact for feedstock distribution
as we assumed for switchgrass, although
distributing energy cane, giant reed, and
napiergrass feedstocks could be less
GHG intensive because higher yields
could translate to shorter overall
hauling distances to storage or biofuel
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production facilities per gallon or Btu of
final fuel produced.
2. Fuel Production, Distribution, and
Use
Energy cane, giant reed, and
napiergrass are suitable for the same
conversion processes as other cellulosic
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feedstocks, such as switchgrass and corn
stover. Currently available information
on energy cane, giant reed, and
napiergrass composition shows that
their hemicellulose, cellulose, and
lignin content are comparable to other
crops that qualify under the RFS
regulations as feedstocks for the
production of cellulosic biofuels. Based
on this similar composition as well as
conversion yield data provided by
industry, we applied the same
production processes that were modeled
for switchgrass in the final RFS2 rule
(biochemical ethanol, thermochemical
ethanol, and Fischer-Tropsch (F–T)
diesel 46) to energy cane, giant reed, and
napiergrass. We assumed the GHG
emissions associated with producing
biofuels from energy cane, giant reed,
and napiergrass are similar to what we
estimated for switchgrass and other
cellulosic feedstocks. EPA also assumes
that the distribution and use of biofuel
made from energy cane, giant reed, and
napiergrass will not differ significantly
from similar biofuel produced from
other cellulosic sources. As was done
for the switchgrass case, this analysis
assumes energy grasses grown in the
United States for production purposes.
If crops were grown internationally,
used for biofuel production, and the fuel
was shipped to the U.S., shipping the
finished fuel to the U.S. could increase
transport emissions. However,
considering the increased transport
emissions associated with sugarcane
ethanol distribution to the U.S., this
would at most add 1–2% to the overall
lifecycle GHG impacts of the energy
grasses.
3. Summary
Based on our comparison of
switchgrass and the three feedstocks
considered here, EPA believes that
cellulosic biofuel produced from the
cellulose, hemicellulose and lignin
portions of energy cane, giant reed, and
napiergrass has similar or better
lifecycle GHG impacts than biofuel
produced from the cellulosic biomass
from switchgrass. Our analysis suggests
that the three feedstocks considered
have GHG impacts associated with
growing and harvesting the feedstock
that are similar to switchgrass.
Emissions from growing and harvesting
energy cane are approximately 4 kg
CO2eq/mmBtu higher than switchgrass,
emissions from growing and harvesting
giant reed are approximately 2 kg
CO2eq/mmBtu lower than switchgrass,
and emissions from growing and
harvesting napiergrass are
46 The F–T diesel process modeled applies to
cellulosic diesel, jet fuel, heating oil, and naphtha.
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approximately 6 kg CO2eq/mmBtu
higher than switchgrass. These are small
changes in the overall lifecycle,
representing at most a 6% change in the
energy grass lifecycle impacts in
comparison to the petroleum fuel
baseline. Furthermore, the three
feedstocks considered are expected to
have similar or lower GHG emissions
than switchgrass associated with other
components of the biofuel lifecycle.
Under a hypothetical worst case, if
the calculated increases in growing and
harvesting the new feedstocks are
incorporated into the lifecycle GHG
emissions calculated for switchgrass,
and other lifecycle components are
projected as having similar GHG
impacts to switchgrass (including land
use change associated with switchgrass
production), the overall lifecycle GHG
reductions for biofuel produced from
energy cane, giant reed, and napiergrass
still meet the 60% reduction threshold
for cellulosic biofuel, the lowest being a
64% reduction (for napiergrass F–T
diesel) compared to the petroleum
baseline. We believe these are
conservative estimates, as use of energy
cane, giant reed, or napiergrass as a
feedstock is expected to have smaller
land-use GHG impacts than switchgrass,
due to their higher yields. The docket
for this rule provides additional detail
on the analysis of energy cane, giant
reed, and napiergrass as biofuel
feedstocks.
Although this analysis assumes
energy cane, giant reed, and napiergrass
biofuels produced for sale and use in
the United States will most likely come
from domestically produced feedstock,
we also intend for the approved
pathways to cover energy cane, giant
reed, and napiergrass from other
countries. We do not expect incidental
amounts of biofuels from feedstocks
produced in other nations to impact our
average GHG emissions. Moreover,
those countries most likely to be
exporting energy cane, giant reed, or
napiergrass or biofuels produced from
these feedstocks are likely to be major
producers which typically use similar
cultivars and farming techniques.
Therefore, GHG emissions from
producing biofuels with energy cane,
giant reed, or napiergrass grown in other
countries should be similar to the GHG
emissions we estimated for U.S. energy
cane, giant reed, or napiergrass, though
they could be slightly (and
insignificantly) higher or lower. For
example, the renewable biomass
provisions under the Energy
Independence and Security Act would
prohibit direct conversion of previously
unfarmed land in other countries into
cropland for energy grass-based
PO 00000
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Sfmt 4700
renewable fuel production.
Furthermore, any energy grass
production on existing cropland
internationally would not be expected
to have land use impacts beyond what
was considered for switchgrass
production. Even if there were
unexpected larger differences, EPA
believes the small amounts of feedstock
or fuel potentially coming from other
countries will not impact our threshold
analysis.
Based on our assessment of
switchgrass in the RFS2 final rule and
this comparison of GHG emissions from
switchgrass and energy cane, giant reed,
and napiergrass, we do not expect
variations to be large enough to bring
the overall GHG impact of fuel made
from energy cane, giant reed or napier
grass to come close to the 60%
threshold for cellulosic biofuel.
Therefore, EPA is including cellulosic
biofuel produced from the cellulose,
hemicelluloses and lignin portions of
energy cane, giant reed, and napiergrass
under the same pathways for which
cellulosic biomass from switchgrass
qualifies under the RFS2 final rule.
C. Lifecycle Greenhouse Gas Emissions
Analysis for Certain Renewable
Gasoline and Renewable Gasoline
Blendstocks Pathways
In this rule, EPA is also adding
pathways to Table 1 to § 80.1426 for the
production of renewable gasoline and
renewable gasoline blendstock using
specified feedstocks, fuel production
processes, and process energy sources.
The feedstocks we considered are
generally considered waste feedstocks
such as crop residues or cellulosic
components of separated yard waste.
These feedstocks have been identified
by the industry as the most likely
feedstocks for use in making renewable
gasoline or renewable gasoline
blendstock in the near term due to their
availability and low cost. Additionally,
these feedstocks have already been
analyzed by EPA as part of the RFS2
rulemaking for the production of other
fuel types. Consequently, no new
modeling is required and we rely on
earlier assessments of feedstock
production and distribution for
assessing the likely lifecycle impact on
renewable gasoline and renewable
gasoline blendstock. We have also relied
on the petroleum gasoline baseline
assessment from the RFS2 rule for
estimating the fuel distribution and use
GHG emissions impacts for renewable
gasoline and renewable gasoline
blendstock. Consequently, the only new
analysis required is of the technologies
for turning the feedstock into renewable
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gasoline and renewable gasoline
blendstock.
1. Feedstock Production and
Distribution
EPA has evaluated renewable gasoline
and renewable gasoline blendstock
pathways that utilize cellulosic
feedstocks currently included in Table 1
to § 80.1426 of the regulations. The
following feedstocks were evaluated:
• Cellulosic biomass from crop
residue, slash, pre-commercial
thinnings and tree residue, annual cover
crops;
• Cellulosic components of separated
yard waste;
• Cellulosic components of separated
food waste; and
• Cellulosic components of separated
MSW.
The FASOM and FAPRI models were
used to analyze the GHG impacts of the
feedstock production portion of a fuel’s
lifecycle. In the RFS2 rulemaking,
FASOM and FAPRI modeling was
performed to analyze the emissions
impact of using corn stover as a biofuel
feedstock and this modeling was
extended to some additional feedstock
sources considered similar to corn
stover. This approach was used for crop
residues, slash, pre-commercial
thinnings, tree residue and cellulosic
components of separated yard, food, and
MSW. These feedstocks are all excess
materials and thus, like corn stover,
were determined to have little or no
land use change GHG impacts. Their
GHG emission impacts are mainly
associated with collection, transport,
and processing into biofuel. See the
RFS2 rulemaking preamble for further
discussion. We used the results of the
corn stover modeling in this analysis to
estimate the upper bound of agricultural
sector impacts from the production of
the various cellulosic feedstocks noted
above.
The agriculture sector modeling
results for corn stover represent all of
the direct and significant indirect
emissions in the agriculture sector
(feedstock production emissions) for a
certain quantity of corn stover
produced. For the RFS2 rulemaking,
this was roughly 62 million dry tons of
corn stover to produce 5.7 billion
gallons of ethanol assuming biochemical
fermentation to ethanol processing. We
have calculated GHG emissions from
feedstock production for that amount of
corn stover. The GHG emissions were
then divided by the total heating value
of the fuel to get feedstock production
emissions per mmBtu of fuel. In
addition to the biochemical ethanol
process, a similar analysis was
completed for thermochemical ethanol
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and F–T diesel pathways as part of the
RFS2 rulemaking.
In this rulemaking we are analyzing
renewable gasoline and renewable
gasoline blendstock produced from corn
stover (and, by extension, other waste
feedstocks). The number of gallons of
fuel produced from a ton of corn stover
(modeled process yields) is specific to
the process used to produce renewable
fuel. EPA has adjusted the results of the
earlier corn stover modeling to reflect
the different process yields and heating
value of renewable gasoline or
renewable gasoline blendstock product.
The results of this calculation are shown
below in Table 7.
We based our process yields and
heating values for renewable gasoline
and renewable gasoline blendstock on
several process technologies
representative of technologies
anticipated to be used in producing
these fuels. As discussed later in this
section, there are four main types of fuel
production technologies available for
producing renewable gasoline. These
four processes can be characterized as
(1) thermochemical gasification, (2)
catalytic pyrolysis and upgrading to
renewable gasoline or renewable gaoline
blendstock (‘‘catalytic pyrolysis’’), (3)
biochemical fermentation with
upgrading to renewable gasoline or
renewable gasoline blendstock via
carboxylic acid (‘‘fermentation and
upgrading’’), and (4) direct biochemical
fermentation to renewable gasoline and
renewable gasoline blendstock (‘‘direct
fermentation’’). The thermochemical
gasification process was modeled as part
of the RFS2 final rule, included as
producing naptha via the F–T process.
Our analysis of the catalytic pyrolysis
process was based on the modeling
work completed by the National
Renewable Energy Laboratory (NREL)
for this rule for a process to make
renewable gasoline blendstock.47 The
fermentation and upgrading process was
modeled based on confidential business
information (CBI) from industry for a
unique process which uses biochemical
conversion of cellulose to renewable
gasoline via a carboxylic acid route. In
addition, we have qualitatively assessed
the direct fermentation to renewable
gasoline process based on similarities to
the biochemical ethanol process already
analyzed as part of the RFS2
rulemaking. The fuel production section
below provides further discussion on
extending the GHG emissions results of
the biochemical ethanol fermentation
47 Kinchin, Christopher. Catalytic Fast Pyrolysis
with Upgrading to Gasoline and Diesel Blendstocks.
National Renewable Energy Laboratory (NREL).
2011.
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Fmt 4701
Sfmt 4700
715
process to a biochemical renewable
gasoline or renewable gasoline
blendstock fermentation process. In
some cases, the available data sources
included process yields for renewable
gasoline or renewable gasoline
blendstock produced from wood chips
rather than corn stover which was
specifically modeled as a feedstock in
the RFS2 final rule. We believe that the
process yields are not significantly
impacted by the source of cellulosic
material whether the cellulosic material
comes from residue such as corn stover
or wood material such as from tree
residues. We made the simplifying
assumption that one dry ton of wood
feedstock produces the same volume of
renewable gasoline or renewable
gasoline blendstock as one dry ton of
corn stover. We believe this is
reasonable considering that the RFS2
rulemaking analyses for biochemical
ethanol and thermochemical F–T diesel
processes showed limited variation in
process yields between different
feedstocks for a given process
technology.48 In addition, since the
renewable gasoline and renewable
gasoline blendstock pathways include
feedstocks that were already considered
as part of the RFS2 final rule, the
existing feedstock lifecycle GHG
impacts for distribution of corn stover
were also applied to this analysis.49
Feedstock production emissions are
shown in Table 7 below for corn stover.
Corn stover feedstock production
emissions are mainly a result of corn
stover removal increasing the
profitability of corn production
(resulting in shifts in cropland and thus
slight emission impacts) and also the
need for additional fertilizer inputs to
replace the nutrients lost when corn
stover is removed. However, corn stover
removal also has an emissions benefit as
it encourages the use of no-till farming
which results in the lowering of
domestic land use change emissions.
This change to no-till farming results in
a negative value for domestic land use
change emission impacts (see also Table
13 below). For other waste feedstocks
(e.g., tree residues and cellulosic
components of separate yard, food, and
MSW), the feedstock production
emissions are even lower than the
values shown for corn stover since the
use of such feedstocks does not require
land use changes or additional
agricultural inputs. Therefore, we
conclude that if the use of corn stover
48 Aden, Andy. Feedstock Considerations and
Impacts on Biorefining. National Renewable Energy
Laboratory (NREL). December 2009.
49 Results for feedstock distribution are
aggregated along with fuel distribution and are
reported in a later section, see conclusion section.
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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations
as a feedstock in the production of
renewable gasoline and renewable
gasoline blendstock yields lifecycle
GHG emissions results for the resulting
fuel that qualify it as cellulosic biofuel
(i.e., it has at least a 60% lifecycle GHG
reduction as compared to conventional
fuel), then the use of other waste
feedstocks with little or no land use
change emissions will also result in
renewable gasoline or renewable
gasoline blendstock that qualifies as
cellulosic biofuel.
TABLE 7—FEEDSTOCK PRODUCTION EMISSIONS FOR RENEWABLE GASOLINE AND RENEWABLE GASOLINE BLENDSTOCK
PATHWAYS USING CORN STOVER
Catalytic pyrolysis
to renewable gasoline blendstock
(g CO2-eq./
mmBtu)
Biochemical fermentation to renewable gasoline
via carboxylic acid
(g CO2-eq./
mmBtu)
Direct biochemical
fermentation process to renewable
gasoline and renewable gasoline
blendstock (g
CO2-eq./mmBtu)
Domestic Livestock ....................................................................................................
Domestic Farm Inputs and Fertilizer N2O .................................................................
Domestic Rice Methane ............................................................................................
Domestic Land Use Change .....................................................................................
International Livestock ...............................................................................................
International Farm Inputs and Fertilizer N2O ............................................................
International Rice Methane ........................................................................................
International Land Use Change .................................................................................
7,648
1,397
366
¥9,124
0
0
0
0
6,770
1,237
324
¥8,076
0
0
0
0
∼ 9,086
∼ 1,660
∼ 434
∼ ¥10,820
0
0
0
0
Total Feedstock Production Emissions ..............................................................
287
254
∼ 361
Feedstock production emission sources
The results in Table 7 differ for the
different pathways considered because
of the different amounts of corn stover
used to produce the same amount of
fuel in each case. Table 7 only considers
the feedstock production impacts
associated with the renewable gasoline
pathways, other aspects of the lifecycle
are discussed in the following sections.
mstockstill on DSK4VPTVN1PROD with RULES3
2. Fuel Distribution
A petroleum gasoline baseline was
developed as part of the RFS2 final rule
which included estimates for fuel
distribution emissions. Since renewable
gasoline and renewable gasoline
blendstocks when blended into gasoline
are similar to petroleum gasoline, it is
reasonable to assume similar fuel
distribution emissions. Therefore, the
existing fuel distribution lifecycle GHG
impacts of the petroleum gasoline
baseline from the RFS2 final rule were
applied to this analysis.
3. Use of the Fuel
A petroleum gasoline baseline was
developed as part of the RFS2 final rule
which estimated the tailpipe emissions
from fuel combustion. Since renewable
gasoline and renewable gasoline
blendstock are similar to petroleum
gasoline, the non-CO2 combustion
emissions calculated as part of the RFS2
final rule for petroleum gasoline were
applied to our analysis of the renewable
gasoline and renewable gasoline
blendstock pathways. Only non-CO2
emissions were included since carbon
fluxes from land use change are
accounted for as part of the biomass
feedstock production.
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4. Fuel Production
In the RFS2 rulemaking, EPA
analyzed several of the main cellulosic
biofuel pathways: a biochemical
fermentation process to ethanol and two
thermochemical gasification processes,
one producing mixed alcohols
(primarily ethanol) and the other one
producing mixed hydrocarbons
(primarily diesel fuel). These pathways
all exceeded the 60% lifecycle GHG
threshold requirements for cellulosic
biofuel using the specified feedstocks.
Refer to the preamble and regulatory
impact analysis (RIA) from the final
RFS2 rule for more details. From these
analyses, it was determined that ethanol
and diesel fuel produced from the
specified cellulosic feedstocks and
processes would be eligible for
cellulosic and advanced biofuel RINs.
The thermochemical gasification
process to diesel fuel (via F–T synthesis)
also produces a smaller portion of
naphtha, a gasoline blendstock. In the
final RFS2 rule, naphtha produced with
specified cellulosic feedstocks by a F–T
process was included as exceeding the
60% lifecycle GHG threshold, with an
applicable D–Code of 3, in Table 1 to
§ 80.1426.
Since the final RFS2 rule was
released, EPA has received several
petitions and inquiries that suggest that
renewable gasoline or renewable
gasoline blendstock produced using
processes other than the F–T process
could also qualify for a similar D–Code
PO 00000
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Fmt 4701
Sfmt 4700
of 3.50 For the reasons described below,
we have decided to authorize the
generation of RINs with a D code of 3
for renewable gasoline and renewable
gasoline blendstock produced using
specified cellulosic feedstocks for the
processes considered here.
Several routes have been identified as
available for the production of
renewable gasoline and renewable
gasoline blendstock from renewable
biomass. These include catalytic
pyrolysis and upgrading to renewable
gasoline or renewable gasoline
blendstock (‘‘catalytic pyrolysis’’),
biochemical fermentation with
upgrading to renewable gasoline or
renewable gasoline blendstock via
carboxylic acid (‘‘fermentation and
upgrading’’), and direct biochemical
fermentation to renewable gasoline and
renewable gasoline blendstock (‘‘direct
fermentation’’).51 52
Similar to how we analyzed several of
the main routes for cellulosic ethanol
and cellulosic diesel for the final RFS2
rule, we have chosen to analyze the
main renewable gasoline and renewable
gasoline blendstock pathways in order
to estimate the potential GHG reduction
profile for renewable gasoline and
renewable gasoline blendstock across a
50 See https://www.epa.gov/otaq/fuels/
renewablefuels/compliancehelp/rfs2-lcapathways.htm for list of petitions received by EPA.
51 Regalbuto, John. ‘‘An NSF perspective on next
generation hydrocarbon biorefineries,’’ Computers
and Chemical Engineering 34 (2010) 1393–1396.
February 2010.
52 Serrano-Ruiz, J., Dumesic, James. ‘‘Catalytic
routes for the conversion of biomass into liquid
hydrocarbon transportation fuels,’’ Energy
Environmental Science (2011) 4, 83–99.
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range of other production technologies
for which we are confident will have at
least as great of GHG emission
reductions as those specifically
analyzed.
a. Catalytic Pyrolysis to Renewable
Gasoline and Renewable Gasoline
Blendstock
The first production process we
investigated for this rule is a catalytic
fast pyrolysis route to bio-oils with
upgrading to a renewable gasoline or a
renewable gasoline blendstock. We
utilized process modeling results from
the National Renewable Energy
Laboratory (NREL). Information
provided by industry and claimed as
CBI are based on similar processing
methods and suggest similar results
than those reported by NREL. Details on
the NREL modeling are described
further in a technical report available
through the docket.53 Catalytic pyrolysis
involves the rapid heating of biomass to
about 500°C at slightly above
atmospheric pressure. The rapid heating
thermally decomposes biomass,
converting it into pyrolysis vapor,
which is condensed into a liquid bio-oil.
The liquid bio-oil can then be upgraded
using conventional hydroprocessing
technology and further separated into
gasoline and diesel blendstock streams
(cellulosic diesel from catalytic
pyrolysis is already included as an
acceptable pathway in the RFS2
program). Some industry sources also
expect to produce smaller fractions of
heating oil in addition to gasoline and
diesel blendstocks. Excess electricity
from the process is also accounted for in
our modeling as a co-product credit in
717
which any excess displaces U.S. average
grid electricity. Excess electricity is
generated from the use of co-product
coke/char and product gases and is
available because internal electricity
demands are fully met. The estimated
energy inputs and electricity credits
shown in Table 8, below, utilize the
data provided by the NREL process
modeling. However, Industry sources
also identified potential areas for
improvements in energy use, such as the
use of biomass fired dryers instead of
natural gas fired dryers for drying
incoming wet feedstocks and increased
turbine efficiencies for electricity
production which may result in lower
energy consumption than estimated by
NREL and thus improve GHG
performance compared to our estimates
here.
TABLE 8—2022 ENERGY USE AT CELLULOSIC BIOFUEL FACILITIES
[Btu/gal]
Technology
Biomass use
Natural gas use
Purchased
electricity
Sold electricity
Catalytic Pyrolysis to Renewable Gasoline Blendstock ..................
136,000
51,000
0
¥2,000
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The emissions from energy inputs
were calculated by multiplying the
amount of energy by emission factors for
fuel production and combustion, based
on the same method and factors used in
the RFS2 final rulemaking. The
emission factors for the different fuel
types are from GREET and were based
on assumed carbon contents of the
different process fuels. The emissions
from producing electricity in the U.S.
were also taken from GREET and
represent average U.S. grid electricity
production emissions.
The major factors influencing the
emissions from the fuel production
stage of the catalytic pyrolysis pathway
are the use of natural gas (mainly due
to hydrogen production for
hydroprocessing) and the co-products
available for additional heat and power
generation.54 See Table 9 for a summary
of emissions from fuel production.
renewable gasoline blendstock. This
process involves the fermentation of
biomass using a mixed-culture of
microorganisms that produce a variety
of carboxylic acids. If the feedstock has
high lignin content, then the biomass is
Catalytic pyrolysis to renewable pretreated to enhance digestibility. The
Lifecycle stage
gasoline
acids are then neutralized to carboxylate
blendstock (g
salts and further converted to ketones
CO2-eq./mmBtu)
and alcohols for refining into gasoline,
diesel, and jet fuel.
On-Site & Upstream EmisThe process requires the use of
sions (Natural Gas &
Biomass*) ......................
31,000 natural gas and hydrogen inputs.55 No
Electricity Co-Product
purchased electricity is required as
Credit .............................
¥3,000 lignin is projected to be used to meet all
Total Fuel Production
facility demands as well as provide
Emissions: .....................
28,000
excess electricity to the grid. EPA used
Only non-CO2 combustion emissions from the estimated energy and material
biomass.
inputs along with emission factors to
estimate the GHG emissions from this
b. Fermentation and Upgrading to
process. The energy inputs and
Renewable Gasoline and Renewable
electricity credits are shown in Table
Gasoline Blendstock
The second production process we
10, below. These inputs are based on
investigated is a biochemical
Confidential Business Information (CBI),
fermentation process to intermediate
rounded to the nearest 1000 units,
carboxylic acids with catalytic
provided by industry as part of the
upgrading to renewable gasoline or
petition process for new fuel pathways.
53 Kinchin, Christopher. Catalytic Fast Pyrolysis
with Upgrading to Gasoline and Diesel Blendstocks.
National Renewable Energy Laboratory (NREL).
2011.
54 A steam methane reformer (SMR) is used to
produce the hydrogen necessary for
hydroprocessing. In the U.S. over 95% of hydrogen
is currently produced via steam reforming (DOE,
2002 ‘‘A National Vision of America’s Transition to
a Hydrogen Economy to 2030 and Beyond’’). Other
alternatives are available, such as renewable or
nuclear resources used to extract hydrogen from
water or the use of biomass to produces hydrogen.
These alternative methods, however, are currently
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TABLE 9—FUEL PRODUCTION EMISSIONS FOR CATALYTIC PYROLYSIS
TO
RENEWABLE
GASOLINE
BLENDSTOCK USING CORN STOVER
PO 00000
Frm 00019
Fmt 4701
Sfmt 4700
not as efficient or cost effective as the use of fossil
fuels and therefore we conservatively estimate
emissions from hydrogen production using the
more commonly used SMR technology.
55 Hydrogen emissions are modeled as natural gas
and electricity demands.
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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations
TABLE 10—2022 ENERGY USE AT CELLULOSIC FACILITY
[Btu/gal]
Technology
Biomass use
Natural gas use
Purchased
electricity
Sold electricity
Biochemical Fermentation to Renewable Gasoline or Renewable
Gasoline Blendstock via Carboxylic Acid .....................................
49,000
59,000
0
¥2,000
The process also uses a small amount
of buffer material as neutralizer which
was not included in the GHG lifecycle
results due to its likely negligible
emissions impact. The GHG emissions
estimates from the fuel production stage
are seen in Table 11.
c. Direct Fermentation to Renewable
Gasoline and Renewable Gasoline
Blendstock
The third production process we
investigated involves the use of
microorganisms to ferment sugars
hydrolyzed from cellulose directly into
hydrocarbons which could be either a
TABLE 11—FUEL PRODUCTION EMIS- complete fuel as renewable gasoline or
SIONS FOR BIOCHEMICAL FERMENTA- a renewable gasoline blendstock. The
TION TO RENEWABLE GASOLINE OR process is similar to the biochemical
RENEWABLE GASOLINE BLENDSTOCK fermentation to ethanol pathway
modeled for the final RFS2 rule with the
VIA CARBOXYLIC ACID USING CORN
major difference being the end fuel
STOVER
product, hydrocarbons instead of
ethanol. Researchers believe that this
GHG Emissions new technology could achieve
Lifecycle stage
(g CO2-eq./
improvements over classical
mmBtu)
fermentation approaches because
hydrocarbons separate spontaneously
On-Site & Upstream Emissions (Natural Gas &
from the aqueous phase, thereby
Biomass*) ......................
33,000 avoiding poisoning of microbes by the
Electricity Co-Product
accumulated products and facilitating
Credit .............................
¥3,000 separation/collection of alkanes from
the reaction medium.56 In other words,
Total Fuel Production
some energy savings may result because
Emissions: ..............
30,000
fewer separation unit operations could
*Only non-CO2 combustion emissions from be required for separating the final
biomass
product from other reactants and there
may be better conversion yields as the
fermentation microorganisms are not
poisoned when interacting with
accumulated products. We also expect
that the lignin/byproduct portions of the
biomass from the fermentation to
hydrocarbon process could be converted
into heat and electricity for internal
demands or for export, similar to the
biochemical fermentation to ethanol
pathway.
Therefore, we can conservatively
extend our final RFS2 rule biochemical
fermentation to ethanol process results
to a similar (but likely slightly
improved) process that instead produces
hydrocarbons. Since the final RFS2 rule
cellulosic ethanol GHG results were
well above the 60% GHG reduction
threshold for cellulosic biofuels, if
actual emissions from other necessary
changes to the direct biochemical
fermentation to hydrocarbons process
represent some small increment in GHG
emissions, the pathway would still
likely meet the threshold. Table 12 is
our qualitative assessment of the
potential emissions reductions from a
process using biochemical fermentation
to cellulosic hydrocarbons assuming
similarities to the biochemical
fermentation to cellulosic ethanol route
from the final RFS2 rule.
TABLE 12—FUEL PRODUCTION EMISSIONS FOR RFS2 CELLULOSIC BIOCHEMICAL ETHANOL COMPARED TO DIRECT
BIOCHEMICAL FERMENTATION TO RENEWABLE GASOLINE OR RENEWABLE GASOLINE BLENDSTOCK USING CORN STOVER
RFS2 Cellulosic
biochemical ethanol emissions (g
CO2-eq./mmBtu)
Direct biochemical
fermentation to renewable gasoline
and renewable
gasoline
blendstock emissions (g CO2-eq./
mmBtu)
On-Site Emissions & Upstream (biomass) ..................................................................................................
Electricity Co-Product Credit .......................................................................................................................
3,000
¥35,000
< or = 3,000
= ¥35,000
Total Fuel Production Emissions 57 ......................................................................................................
¥33,000
< or = ¥33,000
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Lifecycle stage
Table 13 below breaks down by stage
the lifecycle GHG emissions for the
renewable gasoline and renewable
gasoline blendstock pathways using
corn stover and the 2005 petroleum
baseline. The table demonstrates the
56 Serrano-Ruiz, J., Dumesic, James. ‘‘Catalytic
routes for the conversion of biomass into liquid
hydrocarbon transportation fuels,’’ Energy
Environmental Science (2011) 4, 83–99.
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contribution of each stage in the fuel
pathway and its relative significance in
terms of GHG emissions. These results
are also presented in graphical form in
a supplemental memorandum to the
docket.58 As noted above, these analyses
57 Numbers
do not add up due to rounding.
to the Air and Radiation Docket
EPA–HQ–OAR–2011–0542 ‘‘Supplemental
58 Memorandum
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assume natural gas as the process energy
when needed; using biogas or biomass
as process energy would result in an
even better lifecycle GHG impact.
Information for Renewable Gasoline and Renewable
Gasoline Blendstock Pathways Under the
Renewable Fuel Standard (RFS2) Program’’.
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719
TABLE 13—LIFECYCLE GHG EMISSIONS FOR RENEWABLE GASOLINE AND RENEWABLE GASOLINE BLENDSTOCK PATHWAYS
USING CORN STOVER, 2022
[kg CO2-eq./mmBtu]
Catalytic pyrolysis
to renewable gasoline blendstock
Biochemical fermentation to renewable gasoline
via carboxylic acid
Direct biochemical
fermentation to renewable gasoline
and renewable
gasoline
blendstock
9
8
∼ 11
..............................
¥9
¥8
∼ ¥11
..............................
28
2
2
30
2
2
< or = ¥33
∼2
∼1
19
*
79
Total Emissions .........................................................
32
34
< or = ¥29
98
% Change from Baseline ..........................................
¥67%
¥65%
¥129%
..............................
Fuel type
Net Domestic Agriculture (w/o land use change) ....................
Net International Agriculture (w/o land use change):
Domestic Land Use Change ............................................
International Land Use Change:
Fuel Production ................................................................
Fuel and Feedstock Transport .........................................
Tailpipe Emissions ............................................................
2005 gasoline
baseline
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* Emissions included in fuel production stage.
d. Extension of Modeling Results to
Other Production Processes Producing
Renewable Gasoline or Renewable
Gasoline Blendstock
In the RFS2 rulemaking, we modeled
the GHG emissions results from the
biochemical fermentation process to
ethanol, thermochemical gasification
processes to mixed alcohols (primarily
ethanol) and mixed hydrocarbons
(primarily diesel fuel). We extended
these modeled process results to apply
when the biofuel was produced from
‘‘any’’ process. We determined that
since we modeled multiple cellulosic
biofuel processes and all were shown to
exceed the 60% lifecycle GHG threshold
requirements for cellulosic biofuel using
the specified feedstocks its was
reasonable to extend to other processes
that might develop as these would likely
represent improvements over existing
processes as the industry works to
improve the economics of cellulosic
biofuel production by, for example,
reducing energy consumption and
improving process yields. Similarly, this
rule assesses multiple processes for the
production of renewable gasoline and
renewable gasoline blendstocks and all
were shown to exceed the 60% lifecycle
GHG threshold requirements for
cellulosic biofuel using specified
feedstocks.
As was the case in our earlier
rulemaking, a couple reasons in
particular support extending our
modeling results to other production
process producing renewable gasoline
or renewable gasoline blendstock from
cellulosic feedstock. Under this rule we
analyzed the core technologies most
likely available through 2022 for
production of renewable gasoline and
renewable gasoline blendstock routes
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from cellulosic feedstock as shown in
literature. 59 60 The two primary routes
for renewable gasoline and renewable
gasoline blendstock production from
cellulosic feedstock can be classified as
either thermochemical or biological.
Each of these two major categories has
two subcategories. The processes under
the thermochemical category include:
• Pyrolysis—in which cellulosic
biomass is decomposed with
temperature to bio-oils and requires
further catalytic processing to produce a
finished fuel.
• Gasification—in which cellulosic
biomass is decomposed to syngas with
further catalytic processing of methanol
to gasoline or through Fischer-Tropsch
(F–T) synthesis to gasoline.
The processes under the biochemical
category include:
• Direct fermentation—requires the
release of sugars from biomass and the
use of ‘‘synthetic biology’’ in which
microorganisms are altered to ferment
sugars straight into hydrocarbons
instead of alcohols.
• Fermentation w/catalytic
upgrading—requires the release of
sugars from biomass and aqueous- or
liquid-phase processing of sugars or
intermediate fermentation products into
hydrocarbons using solid catalysts,
As part of the modeling effort here, as
well as for the RFS2 final rule, we have
considered the lifecycle GHG impacts of
the four possible production
technologies mentioned above. The
59 Regalbuto, John. ‘‘An NSF perspective on next
generation hydrocarbon biorefineries,’’ Computers
and Chemical Engineering 34 (2010) 1393–1396.
February 2010.
60 Serrano-Ruiz, J., Dumesic, James. ‘‘Catalytic
routes for the conversion of biomass into liquid
hydrocarbon transportation fuels,’’ Energy
Environmental Science (2011) 4, 83–99.
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pyrolysis, direct fermentation, and
fermentation with catalytic upgrading
are considered in this rule and the
gasification route was already included
in the RFS2 final rule. In all cases, the
processes that we have considered meet
the 60% lifecycle GHG reduction
required for cellulosic biofuels.
Furthermore, we believe that the results
from our modeling would cover all the
likely variations within these potential
routes for producing renewable gasoline
and renewable gasoline blendstock
which also use natural gas, biogas or
biomass for process energy and that all
such production variations would also
meet the 60% lifecycle threshold.
The main reason for this is that we
believe that our energy input
assumptions are reasonable at this time
but probably in some cases conservative
for commercial scale cellulosic
facilities. The cellulosic industry is in
its early stages of development and
many of the estimates of process
technology GHG impacts is based on
pre-commercial scale assessments and
demonstration programs. Commercial
scale cellulosic facilities will continue
to make efficiency improvements over
time to maximize their fuel products/coproducts and minimize wastes. For
cellulosic facilities, such improvements
include increasing conversion yields
and fully utilizing the biomass input for
valuable products.
An example of increasing the amount
of biomass utilized is the combustion of
undigested or unconverted biomass for
heat and power. The three routes that
we analyzed for the production of
renewable gasoline and renewable
gasoline blendstock in today’s rule
assume an electricity production credit
from the economically-driven use of
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lignin or waste byproducts; we also ran
a sensitivity case where no electricity
credit was given. We found that all of
the routes analyzed would still pass the
GHG threshold without an electricity
credit, providing confidence that over
the range of technology options, these
process technologies will surely allow
the cellulosic biofuel produced to
exceed the threshold for cellulosic
biouel GHG performance. Without
excess electricity production the
catalytic pyrolysis pathway results in a
65% lifecycle GHG reduction, the
biochemical fermentation via carboxylic
acid pathway results in a 62% lifecycle
GHG reduction, and the direct
biochemical fermentation pathway
results in a 93% reduction in lifecycle
GHG emissions compared to the
petroleum fuel baseline.
Additionally, while the final results
reported in this rule include an
electricity credit, this electricity credit
is based on current technology for
generating electricity; it is possible that
over the next decade as cellulosic
biofuel production matures, the
efficiency with which electricity is
generated at these facilities will also
improve. Such efficiency improvements
will tend to improve the GHG
performance for cellulosic biofuel
technologies in general including those
used to produce renewable gasoline.
Furthermore, industry has identified
other areas for energy improvements
which our current pathway analyses do
not include. Therefore, the results we
have come up with for the individual
pathway types represent conservative
estimates and any variations in the
pathways considered are likely to result
in greater GHG reductions that what is
considered here. For example, the
variation of the catalytic pyrolysis route
considered here resulted in a 67%
reduction in lifecycle GHG emissions
compared to the petroleum baseline.
However, as was mentioned this was
based on data from our NREL modeling
and industry CBI data indicated more
efficient energy performance which, if
realized, would improve GHG
performance. Another area for
improvement in this pathway could be
the use of anaerobic digestion to treat
organics in waste water. If the anaerobic
digestion is on-site, then enough biogas
could potentially be produced to replace
all of the fossil natural gas used as fuel
and about half the natural gas fed for
hydrogen production.61 Thus, fossil
natural gas consumption could be
61 Kinchin, Christopher. Catalytic Fast Pyrolysis
with Upgrading to Gasoline and Diesel Blendstocks.
National Renewable Energy Laboratory (NREL).
2011.
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further minimized under certain
scenarios. We believe that as
commercial scale cellulosic facilities
develop, more of these improvements
will be made to maximize the use of all
the biomass and waste byproducts
available to bring the facility closer to
energy self-sufficiency. These
improvements could help to increase
the economic profitability for cellulosic
facilities where fossil energy inputs
become costly to purchase. Therefore
we can extend the modeling results for
our pyrolysis route to all variations of
this production technology which use
natural gas, biogas or biomass for
production energy for producing
renewable gasoline or renewable
gasoline blendstock.
The F–T gasification technology route
considered as part of the RFS2 final rule
resulted in an approximately 91%
reduction in lifecycle GHG emissions
compared to the petroleum baseline.
This could be considered a conservative
estimate as the process did not assume
any excess electricity production, which
as mentioned above could lead to
additional GHG reductions. The F–T
process involves gasifying biomass into
syngas (mix of H2 and CO) and then
converting the syngas through a
catalytic process into a hydrocarbon mix
that is further refined into finished
product. The F–T process considered
was based on producing both gasoline
and diesel fuel so that it was not
optimized for renewable gasoline
production. A process for producing
primarily renewable gasoline rather
than diesel from a gasification route
should not result in a significantly
worse GHG impacts compared to the
mixed fuel process analyzed.
Furthermore, as the lifecycle GHG
reduction from the F–T process
considered was around 91%, there is
considerable room for variations in this
route to still meet the 60% lifecycle
GHG reduction threshold for cellulosic
fuels. Therefore, in addition to the F–T
process orginially analyzed for
producing naphtha, we can extend the
results based on the above analyses to
include all variations of the gasification
route which use natural gas, biogas or
biomass for production energy for
producing renewable gasoline or
renewable gasoline blendstock. These
variations include for example different
catalysts and different refining
processes to produce different mixes of
final fuel product. While the current
Table 1 entry in the regulations does not
specify process energy sources, we are
adding these specific eligible energy
sources since we have not analyzed
other energy sources (e.g. coal) as also
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allowing the pathway to meet the GHG
performance threshold.
There is an even wider gap between
the results modeled for the direct
fermentation route and the cellulosic
lifecycle GHG threshold. The variation
we considered for the direct
fermentation process resulted in an
approximately 129% reduction in
lifecycle GHG emissions compared to
the petroleum baseline. This process did
consider production of electricity as
part of the process but as mentioned
even if this was not the case the
pathway would still easily fall below
the 60% lifecycle threshold for
cellulosic biofuels. If actual emissions
from other necessary changes to the
direct biochemical fermentation to
hydrocarbons process represent some
small increment in GHG emissions, the
pathway would still likely meet the
threshold. Therefore, we can extend the
results to all variations of the direct
biochemical route for renewable
gasoline or renewable gasoline
blendstock production which use
natural gas, biogas or biomass for
production energy.
The biochemical with catalytic
upgrading route that we evaluated
resulted in a 65% reduction in GHG
emissions compared to the petroleum
baseline. However, this can be
considered a conservative estimate. For
instance, the biochemical fermentation
to gasoline via carboxylic acid route
considered did not include the potential
for generating steam from the
combustion of undigested biomass and
then using this steam for process energy.
If this had been included, natural gas
consumption could potentially be
decreased which would lower the
potential GHG emissions estimated from
the process. Therefore, the scenario
analyzed could be considered
conservative in estimating actual natural
gas usage. As was the case with the
pyrolysis route considered, we believe
that as commercial scale cellulosic
facilities develop, improvements will be
made to maximize the use of all the
biomass and waste byproducts available
to bring the facility closer to energy selfsufficiency. These improvements help
to increase the economic profitability
for cellulosic facilities where fossil
energy inputs become costly to
purchase. The processes we analyzed
for this rulemaking utilized a mix of
natural gas and biomass for process
energy, with biogas replacing natural
gas providing improved GHG
performance. We have not analyzed
other fuel types (e.g., coal) and are
therefore not approving processes that
utilized other fuel sources at this point.
Therefore, we are extending our results
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to include all variations of the
biochemical with catalytic upgrading
process utilizing natural gas, biogas or
biomass for process energy.
While actual cellulosic facilities may
show some modifications to the process
scenarios we have already analyzed, our
results give a good indication of the
range of emissions we could expect
from processes producing renewable
gasoline and renewable gasoline
blendstock from cellulosic feedstock, all
of which meet the 60% cellulosic
biofuel threshold (assuming they are
utilizing natural gas, biogas or biomass
for process energy). Technology changes
in the future are likely to increase
efficiency to maximize profits, while
also lowering lifecycle GHG emissions.
Therefore, we have concluded that since
all of the renewable gasoline or
renewable gasoline blendstock fuel
processing methods we have analyzed
exceed the 60% threshold using specific
cellulosic feedstock types, we can
conclude that processes producing
renewable gasoline or renewable
gasoline blendstock that fit within the
categories of process analyzed here and
are produced from the same feedstock
types and using natural gas, biogas or
biomass for process energy use will also
meet the 60% GHG reduction threshold.
In addition, while other technologies
may develop, we expect that they will
only become commercially competitive
if they have better yield (more gallons
per ton of feedstock) or lower
production cost due to lower energy
consumption. Both of these factors
would suggest better GHG performance.
This would certainly be the case if such
processes also relied upon using biogas
and/or biomass as the primary energy
source. Therefore based on our review
of the existing primary cellulosic biofuel
production processes, likely GHG
emission improvements for existing or
new technologies, and consideration of
the positive GHG emissions benefits
associated with using biogas and/or
biomass for process energy, we are
approving for cellulosic RIN generation
any process for renewable gasoline and
renewable gasoline blendstock
production using specified cellulosic
biomass feedstocks as long as the
process utilizes biogas and/or biomass
for all process energy.
5. Summary
Three renewable gasoline and
renewable gasoline blendstock
pathways were compared to baseline
petroleum gasoline, using the same
value for baseline gasoline as in the
RFS2 final rule analysis. The results of
the analysis indicate that the renewable
gasoline and renewable gasoline
blendstock pathways result in a GHG
emissions reduction of 65–129% or
better compared to the gasoline fuel it
would replace using corn stover as a
feedstock. Since the renewable gasoline
and renewable gasoline blendstock
pathways which use corn stover as a
feedstock all exceed the 60% lifecycle
GHG threshold requirements for
cellulosic biofuel, and since these
pathways capture the likely current
technologies and since future
technology improvements are likely to
increase efficiency and lower GHG
emissions, we have determined that all
processes producing renewable gasoline
or renewable gasoline blendstock from
corn stover can qualify if they fall in the
following process characterizations:
• Catalytic pyrolysis and upgrading
utilizing natural gas, biogas, and/or
biomass as the only process energy
sources.
• Gasification and upgrading utilizing
natural gas, biogas, and/or biomass as
the only process energy sources.
• Direct fermentation utilizing natural
gas, biogas, and/or biomass as the only
process energy sources.
• Fermentation and upgrading
utilizing natural gas, biogas, and/or
biomass as the only process energy
sources.
• Any process utilizing biogas and/or
biomass as the only process energy
sources.
As was the case for extending corn
stover results to other feedstocks in the
RFS2 final rule, these results are also
reasonably extended to feedstocks with
similar or lower GHG emissions
profiles, including the following
feedstocks:
• Cellulosic biomass from crop
residue, slash, pre-commercial
thinnings and tree residue, annual cover
crops;
• Cellulosic components of separated
yard waste;
• Cellulosic components of separated
food waste; and
• Cellulosic components of separated
MSW.
For more information on the
reasoning for extension to these other
feedstocks refer to the feedstock
production and distribution section or
the RFS2 rulemaking (75 FR 14793–
14795).
Based on these results, today’s rule
includes pathways for the generation of
cellulosic biofuel RINs for renewable
gasoline or renewable gasoline
blendstock produced by catalytic
pyrolysis and upgrading, gasification
and upgrading, direct fermentation,
fermentation and upgrading, all
utilizing natural gas, biogas, and/or
biomass as the only process energy
sources or any process utilizing biogas
and/or biomass as the only energy
sources, and using corn stover as a
feedstock or the feedstocks noted above.
In order to qualify for RIN generation,
the fuel must meet the other definitional
criteria for renewable fuel (e.g.,
produced from renewable biomass, and
used to reduce or replace petroleumbased transportation fuel, heating oil or
jet fuel) specified in the Clean Air Act
and the RFS regulations.
A manufacturer of a renewable motor
vehicle gasoline (including parties using
a renewable blendstock obtained from
another party), must satisfy EPA motor
vehicle registration requirements in 40
CFR Part 79 for the fuel to be used as
a transportation fuel. Per 40 CFR
79.56(e)(3)(i), a renewable motor vehicle
gasoline would be in the Non-Baseline
Gasoline category or the Atypical
Gasoline category (depending on its
properties) since it is not derived only
from conventional petroleum, heavy oil
deposits, coal, tar sands and/or oil sands
(40 CFR 79.56(e)(3)(i)(5)).In either case,
the Tier 1 requirements at 40 CFR 79.52
(emissions characterization) and the
Tier 2 requirements at 40 CFR 79.53
(animal exposure) are conditions for
registration unless the manufacturer
qualifies for a small business provision
at 40 CFR 79.58(d). For a non-baseline
gasoline, a manufacturer under $50
million in annual revenue is exempt
from Tier 1 and Tier 2. For an atypical
gasoline there is no exemption from Tier
1, but a manufacturer under $10 million
in annual revenue is exempt from Tier
2.
Registration for a motor vehicle
gasoline at 40 CFR 79 is via EPA Form
3520–12, Fuel Manufacturer
Notification for Motor Vehicle Fuel,
available at: https://www.epa.gov/otaq/
regs/fuels/ffarsfrms.htm.
D. Esterification Production Process
Inclusion for Specified Feedstocks
Producing Biodiesel
Table 14, shown below, includes
pathways for biodiesel using specified
feedstocks and the production process
transesterification. Transesterification is
the most commonly used method to
produce biodiesel (i.e., methyl esters) by
62 Commonly used base catalysts include sodium
hydroxide (NaOH), potassium hydroxide (KOH) and
sodium methoxide (NaOCH3).
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reacting triglycerides with methanol
typically under the presence of a base
catalyst, see the simplified form in
Equation 1.62
TABLE 14—EXCERPTS OF EXISTING FUEL PATHWAYS FROM § 40 CFR 80.1426
Fuel type
Feedstock
Production process requirements
D-Code
Biodiesel, and renewable diesel .......
Soy bean oil; Oil from annual
covercrops; Algal oil; Biogenic
waste oils/fats/greases; Non-food
grade corn oil.
4 (Biomass-Based Diesel).
Biodiesel, and renewable diesel .......
Soy bean oil; Oil from annual
covercrops; Algal oil; Biogenic
waste oils/fats/greases; Non-food
grade corn oil.
One of the following: TransEsterification Hydrotreating Excluding processes that co-process
renewable biomass and petroleum.
One of the following: TransEsterification Hydrotreating Includes only processes that coprocess renewable biomass and
petroleum.
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Biodiesel feedstock
Refined vegetable oils ..............
Crude vegetable oils .................
Restaurant waste grease .........
Yellow grease ...........................
Animal fat ..................................
Brown grease ...........................
Trap grease ..............................
Percentage
FFA
<0.05
0.3–0.7
2–7
<15
5–30
>15
40–100
One of the most widely used methods
for treating biodiesel feedstocks with
higher FFA content is acid catalysis.
Acid catalysis typically uses a strong
acid such as sulfuric acid to catalyze the
63 Van Gerpen, J., Shanks, B., Pruszko, R.,
Clements, D., Knothe, G., ‘‘Biodiesel Production
Technology,’’ NREL/SR–510–36244, July 2004.
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esterification of the FFAs and the
transesterification of the triglycerides.
The simplified form of the esterification
process is given below in Equation 2.
Acid esterification can be applied to
feedstocks with FFA contents above 5%.
Because the transesterification of
triglycerides is slow under acid
catalysis, a technique commonly used to
overcome the reaction rate issue is to
first convert the FFAs through an acid
esterification (also known as an acid
‘‘pretreatment’’ step), and then followup with the traditional base-catalyzed
transesterification of triglycerides. See
Figure 2 for a general flow diagram of
the acid esterification and subsequent
transesterification biodiesel process.
64 Van Gerpen, J., ‘‘Used and Waste Oil and
Grease for Biodiesel,’’ NC State University A&T
State University Cooperative Extension, https://
www.extension.org/pages/Used_and_Waste_Oil_
and_Grease_for_Biodiesel.
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62 Commonly used base catalysts include sodium
hydroxide (NaOH), potassium hydroxide (KOH) and
sodium methoxide (NaOCH3).
TABLE 15—RANGES OF FFA IN
BIODIESEL FEEDSTOCKS 63 64
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While triglycerides are usually the
main component of oils, fats, and grease
feedstocks, there are other components
such as free fatty acids (FFAs) that are
typically removed prior to
transesterification. Removal or
conversion of FFAs is important if the
traditional base-catalyzed
transesterification production process is
used since FFAs will react with base
catalysts to produce soaps that inhibit
the transesterification reaction. Table 15
below gives the usual ranges for FFAs
found in biodiesel feedstocks.
5 (Advanced Biofuel).
Under the RFS2 final rule, biodiesel
from biogenic waste oils/fats/greases
qualifies for D-Codes 4 and 5 using a
‘‘transesterification’’ process. This
conclusion was based on the analysis of
yellow grease as a feedstock in a process
where there was an acid ‘‘pretreatment’’
or ‘‘esterification’’ process to treat the
FFAs contained in the feedstock. In fact,
one of the material inputs assumed in
the modeling for the final RFS2 rule
yellow grease pathway is sulfuric acid,
which is the catalyst commonly used for
acid esterification. However, we had not
stipulated ‘‘esterification’’ as a qualified
production process in Table 1 to § 40
CFR 80.1426. We believe this ambiguity
could unnecessarily cause confusion as
to whether esterification can also be
used for the production of biodiesel
under the currently approved pathways.
Since the biodiesel modeling
completed for the final RFS2 rule
actually includes esterification
upstream of the transesterification
process, we find it appropriate to clarify
Table 1 to § 40 CFR 80.1426 to include
‘‘esterification’’ as a qualified process in
which to produce biodiesel. As the
modeling for yellow grease met an 86%
GHG reduction emissions level, and
yellow grease is typically <15% FFA
content, it is reasonable to conclude that
esterification and subsequent
transesterification with a yellow grease
feedstock containing FFAs at the very
least up to 15% can meet the GHG
reduction threshold for biomass-based
diesel and advanced biofuel of 50%.
As noted in Table 15, however, there
are feedstocks that may contain even
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higher levels of FFAs. As described
below, EPA has evaluated the use of
these higher FFA feedstocks to make
biodiesel and has determined that use of
such feedstocks also results in a
biodiesel with lifecycle GHG emissions
at least 50% less than that of
conventional fuel.
The National Biodiesel Board (NBB)
has conducted a comprehensive survey
of the actual energy used by commercial
biodiesel production plants in the U.S.65
The survey depicts the amount of
energy and incidental process materials
such as acids used to produce a gallon
of biodiesel. The survey data returned
represents 37% of the surveyed 230
NBB biodiesel members in 2008 and
includes producers using a variety of
virgin oils and recycled or reclaimed
fats and oils. While there is no specific
data on the FFA content of the
feedstocks used, the feedstocks did
include reclaimed greases which
represent the feedstocks which typically
have the highest FFA content. As the
data is partially aggregated, we used the
maximum surveyed electricity and
natural gas used at the facilities and a
high estimate of ‘‘materials used’’ based
on a sum of industry averages for all
process materials for calculating
potential GHG emissions. Even though
some of the facilities might be
processing feedstocks with relatively
low FFA content, we believe that using
these maximum observed inputs for
energy used plus a high estimate for
process materials used will estimate the
highest GHG emissions profile for
biodiesel production GHG emissions.
When combined with the feedstock
GHG emissions impact (see discussion
below), the results still predict a GHG
emissions reduction comfortably
exceeding 50% as compared to the
petroleum fuel it displaces. Therefore,
there is little risk in predicting that any
facility that utilizes esterification and
feedstock over the range of likely FFA
content can meet the 50% biomassbased diesel and advanced biofuel
threshold.
According to the survey, the
maximum electricity use for a producer
reached as high as 3,071 Btu per gallon
biodiesel. This is about 5 times higher
than the industry average. The
maximum natural gas usage for a
producer reached as high as 12,324 Btu
per gallon biodiesel, which is about 3.5
times higher than the industry average.
For ‘‘materials used’’ only an industry
average for each material was provided
in the survey. Therefore, as a
conservative estimate, we totaled all the
average material inputs to equal 0.51 kg/
gal biodiesel.66 We believe that this is
conservative because not all facilities
are likely to use each and every one of
the process materials listed in the
survey (e.g., we totaled all the acids
65 National Biodiesel Board, Comprehensive
Survey on Energy Use for Biodiesel Production
(2008) https://www.biodiesel.org/news/RFS/
rfs2docs/NBB%20Energy%20Use%20Survey%20
FINAL.pdf.
66 The material inputs include methanol, sodium
methylate, sodium hydroxide, potassium
hydroxide, hydrochloric acid, sulfuric acid,
phosphoric acid, and citric acid. The majority of
material input is from methanol.
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used even though a facility is not likely
to use each different acid). Thus, our
estimate of materials used will estimate
a level of maximum usage of materials
at a given facility. In addition, we did
not include a glycerin co-product credit
when calculating emissions since the
esterification reaction does not produce
glycerin (see Equation 2). Using the
same methodology as was used for the
yellow grease modeling under RFS2, but
using the high energy and materials use
assumptions per the above discussion
and omitting the glycerin co-product
credit, we estimate the emissions from
biodiesel processing at 23,708 gCO2eq
per mmBtu of biodiesel. The estimated
GHG emissions reduction for the entire
process is ¥71%. Since the GHG
threshold is at ¥50% for biomass-based
diesel and advanced biofuel, we believe
that there is a large enough margin in
the results to reasonably conclude that
biodiesel using esterification of
specified feedstocks with any level of
FFA content meets the biomass-based
diesel and advanced biofuel 50%
lifecycle GHG reduction threshold.
Therefore, we are including the process
‘‘esterification’’ as an approved
biodiesel production process in Table 1
to § 40 CFR 80.1426. In addition,
consistent with the modeling conducted
for RFS2, we interpret the RFS
regulations as they existed prior to
today’s rule as including a direct
esterification process as part of the
biodiesel pathways for which only
‘‘trans-esterification’’ was specifically
referenced in Table 1 to § 40 CFR
80.1426.
V. Additional Changes to Listing of
Available Pathways in Table 1 of
80.1426
We are also finalizing two changes to
Table 1 to 80.1426 that were proposed
on July 1, 2011 (76 FR 38844). The first
change adds ID letters to pathways to
facilitate references to specific
pathways. The second change adds
‘‘rapeseed’’ to the existing pathway for
renewable fuel made from canola oil.
On September 28, 2010, EPA
published a ‘‘Supplemental
Determination for Renewable Fuels
Produced Under the Final RFS2
Program from Canola Oil’’ (FR Vol. 75,
No. 187, pg 59622–59634). In the July 1,
2011 NPRM (76 FR 38844) we proposed
to clarify two aspects of the
supplemental determination. First we
proposed to amend the regulatory
language in Table 1 to § 80.1426 to
clarify that the currently-approved
pathway for canola also applies more
generally to rapeseed. While ‘‘canola’’
was specifically described as the
feedstock evaluated in the supplemental
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determination, we had not intended the
supplemental determination to cover
just those varieties or sources of
rapeseed that are identified as canola,
but to all rapeseed. As described in the
July 1, 2011 NPRM, we currently
interpret the reference to ‘‘canola’’ in
Table 1 to § 80.1426 to include any
rapeseed. To eliminate ambiguity
caused by the current language,
however, we proposed to replace the
term ‘‘canola’’ in that table with the
term ‘‘canola/rapeseed’’. Canola is a
type of rapeseed. While the term
‘‘canola’’ is often used in the American
continent and in Australia, the term
‘‘rapeseed’’ is often used in Europe and
other countries to describe the same
crop. We received no adverse comments
on our proposal, and thus are finalizing
it as proposed. This change will
enhance the clarity of the regulations
regarding the feedstocks that qualify
under the approved canola biodiesel
pathway.
Second, we wish to clarify that
although the GHG emissions of
producing fuels from canola feedstock
grown in the U.S. and Canada was
specifically modeled as the most likely
source of canola (or rapeseed) oil used
for biodiesel produced for sale and use
in the U.S., we also intended that the
approved pathway cover canola/
rapeseed oil from other countries, and
we interpret our regulations in that
manner. We expect the vast majority of
biodiesel used in the U.S. and produced
from canola/rapeseed oil will come from
U.S. and Canadian crops. Incidental
amounts from crops produced in other
nations will not impact our average
GHG emissions for two reasons. First,
our analyses considered world-wide
impacts and thus considered canola/
rapeseed crop production in other
countries. Second, other countries most
likely to be exporting canola/rapeseed
or biodiesel product from canola/
rapeseed are likely to be major
producers which typically use similar
cultivars and farming techniques.
Therefore, GHG emissions from
producing biodiesel with canola/
rapeseed grown in other countries
should be very similar to the GHG
emissions we modeled for Canadian and
U.S. canola, though they could be
slightly (and insignificantly) higher or
lower. At any rate, even if there were
unexpected larger differences, EPA
believes the small amounts of feedstock
or fuel potentially coming from other
countries will not impact our threshold
analysis. Therefore, EPA interprets the
approved canola pathway as covering
canola/rapeseed regardless of country
origin.
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VI. Statutory and Executive Order
Reviews
A. Executive Order 12866: Regulatory
Planning and Review
This action is not a ‘‘significant
regulatory action’’ under the terms of
Executive Order 12866 (58 FR 51735,
October 4, 1993) and is therefore not
subject to review under Executive
Orders 12866 and 13563 (76 FR 3821,
January 21, 2011).
B. Paperwork Reduction Act
This action does not impose any new
information collection burden. The
corrections, clarifications, and
modifications to the final RFS2
regulations contained in this rule are
within the scope of the information
collection requirements submitted to the
Office of Management and Budget
(OMB) for the final RFS2 regulations.
OMB has approved the information
collection requirements contained in the
existing regulations at 40 CFR part 80,
subpart M under the provisions of the
Paperwork Reduction Act, 44 U.S.C.
3501 et seq. and has assigned OMB
control numbers 2060– 0637 and 2060–
0640. The OMB control numbers for
EPA’s regulations in 40 CFR are listed
in 40 CFR part 9.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA)
generally requires an agency to prepare
a regulatory flexibility analysis of any
rule subject to notice and comment
rulemaking requirements under the
Administrative Procedure Act or any
other statute unless the agency certifies
that the rule will not have a significant
economic impact on a substantial
number of small entities. Small entities
include small businesses, small
organizations, and small governmental
jurisdictions.
For purposes of assessing the impacts
of today’s rule on small entities, small
entity is defined as: (1) A small business
as defined by the Small Business
Administration’s (SBA) regulations at 13
CFR 121.201; (2) a small governmental
jurisdiction that is a government of a
city, county, town, school district or
special district with a population of less
than 50,000; and (3) a small
organization that is any not-for-profit
enterprise which is independently
owned and operated and is not
dominant in its field.
After considering the economic
impacts of this action on small entities,
I certify that this rule will not have a
significant economic impact on a
substantial number of small entities.
This rule will not impose any new
requirements on small entities. The
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governments. Thus, Executive Order
13175 does not apply to this action.
relatively minor corrections and
modifications this rule makes to the
final RFS2 regulations do not impact
small entities.
D. Unfunded Mandates Reform Act
This rule does not contain a Federal
mandate that may result in expenditures
of $100 million or more for State, local,
and tribal governments, in the aggregate,
or the private sector in any one year. We
have determined that this action will
not result in expenditures of $100
million or more for the above parties
and thus, this rule is not subject to the
requirements of sections 202 or 205 of
UMRA.
This rule is also not subject to the
requirements of section 203 of UMRA
because it contains no regulatory
requirements that might significantly or
uniquely affect small governments. It
only applies to gasoline, diesel, and
renewable fuel producers, importers,
distributors and marketers and makes
relatively minor corrections and
modifications to the RFS2 regulations.
E. Executive Order 13132 (Federalism)
This action does not have federalism
implications. It will not have substantial
direct effects on the States, on the
relationship between the national
government and the States, or on the
distribution of power and
responsibilities among the various
levels of government, as specified in
Executive Order 13132. This action only
applies to gasoline, diesel, and
renewable fuel producers, importers,
distributors and marketers and makes
relatively minor corrections and
modifications to the RFS2 regulations.
Thus, Executive Order 13132 does not
apply to this action.
F. Executive Order 13175 (Consultation
and Coordination With Indian Tribal
Governments)
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This rule does not have tribal
implications, as specified in Executive
Order 13175 (65 FR 67249, November 9,
2000). It applies to gasoline, diesel, and
renewable fuel producers, importers,
distributors and marketers. This action
makes relatively minor corrections and
modifications to the RFS regulations,
and does not impose any enforceable
duties on communities of Indian tribal
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G. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
EPA interprets EO 13045 (62 FR
19885, April 23, 1997) as applying only
to those regulatory actions that concern
health or safety risks, such that the
analysis required under section 5–501 of
the EO has the potential to influence the
regulation. This action is not subject to
EO 13045 because it does not establish
an environmental standard intended to
mitigate health or safety risks.
H. Executive Order 13211: Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
This rule is not subject to Executive
Order 13211 (66 FR 18355 (May 22,
2001)), because it is not a significant
regulatory action under Executive Order
12866.
I. National Technology Transfer and
Advancement Act
Section 12(d) of the National
Technology Transfer and Advancement
Act of 1995 (‘‘NTTAA’’), Public Law
104–113, 12(d) (15 U.S.C. 272 note)
directs EPA to use voluntary consensus
standards in its regulatory activities
unless to do so would be inconsistent
with applicable law or otherwise
impractical. Voluntary consensus
standards are technical standards (e.g.,
materials specifications, test methods,
sampling procedures, and business
practices) that are developed or adopted
by voluntary consensus standards
bodies. NTTAA directs EPA to provide
Congress, through OMB, explanations
when the Agency decides not to use
available and applicable voluntary
consensus standards.
This action does not involve technical
standards. Therefore, EPA did not
consider the use of any voluntary
consensus standards.
J. Executive Order 12898: Federal
Actions To Address Environmental
Justice in Minority Populations and
Low-Income Populations
Executive Order (EO) 12898 (59 FR
7629 (Feb. 16, 1994)) establishes Federal
executive policy on environmental
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725
justice. Its main provision directs
Federal agencies, to the greatest extent
practicable and permitted by law, to
make environmental justice part of their
mission by identifying and addressing,
as appropriate, disproportionately high
and adverse human health or
environmental effects of their programs,
policies, and activities on minority
populations and low-income
populations in the United States.
EPA has determined that this rule will
not have disproportionately high and
adverse human health or environmental
effects on minority or low-income
populations because it does not affect
the level of protection provided to
human health or the environment.
These amendments would not relax the
control measures on sources regulated
by the RFS regulations and therefore
would not cause emissions increases
from these sources.
K. Congressional Review Act
The Congressional Review Act, 5
U.S.C. 801 et seq., as added by the Small
Business Regulatory Enforcement
Fairness Act of 1996, generally provides
that before a rule may take effect, the
agency promulgating the rule must
submit a rule report, which includes a
copy of the rule, to each House of the
Congress and to the Comptroller General
of the United States. A major rule
cannot take effect until 60 days after it
is published in the Federal Register.
EPA will submit a report containing this
rule and other required information to
the U.S. Senate, the U.S. House of
Representatives, and the Comptroller
General of the United States prior to
publication of the rule in the Federal
Register. This action is not a ‘‘major
rule’’ as defined by 5 U.S.C. 804(2).
VII. Statutory Provisions and Legal
Authority
Statutory authority for the rule
finalized today can be found in section
211 of the Clean Air Act, 42 U.S.C.
7545. Additional support for the
procedural and compliance related
aspects of today’s rule, including the
recordkeeping requirements, come from
Sections 114, 208, and 301(a) of the
Clean Air Act, 42 U.S.C. 7414, 7542, and
7601(a).
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List of Subjects in 40 CFR Part 80
Environmental protection,
Administrative practice and procedure,
Agriculture, Air pollution control,
Confidential business information,
Diesel Fuel, Energy, Forest and forest
products, Fuel additives, Gasoline,
Imports, Labeling, Motor vehicle
pollution, Penalties, Petroleum,
Reporting and recordkeeping
requirements.
Dated: November 30, 2011.
Lisa P. Jackson,
Administrator.
PART 80—REGULATION OF FUELS
AND FUEL ADDITIVES
1. The authority citation for part 80
continues to read as follows:
■
Authority: 42 U.S.C. 7414, 7521(1), 7545
and 7601(a).
2. Section 80.1401 is amended by
addition of the following definitions of
‘‘Renewable Gasoline’’ and ‘‘Renewable
Gasoline Blendstock’’ in alphabetical
order to read as follows:
■
§ 80.1401
Definitions.
*
For the reasons set forth in the
preamble, 40 CFR part 80 is amended as
follows:
*
*
*
*
Renewable gasoline means renewable
fuel made from renewable biomass that
is composed of only hydrocarbons and
which meets the definition of gasoline
in § 80.2(c).
Renewable gasoline blendstock means
a blendstock made from renewable
biomass that is composed of only
hydrocarbons and which meets the
definition of gasoline blendstock in
§ 80.2(s).
*
*
*
*
*
■ 3. Section 80.1426 is amended by
revising Table 1 in paragraph (f)(1) to
read as follows:
§ 80.1426 How are RINs generated and
assigned to batches of renewable fuel by
renewable fuel producers or importers?
*
*
*
(f) * * *
(1) * * *
*
*
TABLE 1 TO § 80.1426—APPLICABLE D CODES FOR EACH FUEL PATHWAY FOR USE IN GENERATING RINS
Fuel type
Feedstock
Production process requirements
All of the following: Dry mill process, using natural
gas, biomass, or biogas for process energy and
at least two advanced technologies from Table 2
to this section.
All of the following: Dry mill process, using natural
gas, biomass, or biogas for process energy and
at least one of the advanced technologies from
Table 2 to this section plus drying no more than
65% of the distillers grains with solubles it markets annually.
All of the following: Dry mill process, using natural
gas, biomass, or biogas for process energy and
drying no more than 50% of the distillers grains
with solubles it markets annually.
Wet mill process using biomass or biogas for process energy.
Fermentation using natural gas, biomass, or biogas
for process energy.
One of the following: Trans-Esterification,
Esterification Hydrotreating Excluding processes
that co-process renewable biomass and petroleum.
Trans-Esterification using natural gas or biomass
for process energy.
One of the following: Trans-Esterification,
Esterification Hydrotreating Includes only processes that co-process renewable biomass and
petroleum.
Hydrotreating ............................................................
Fermentation ............................................................
Any ...........................................................................
6
Any ...........................................................................
7
A
Ethanol .......................
Corn starch ..............................................................
B
Ethanol .......................
Corn starch ..............................................................
C
Ethanol .......................
Corn starch ..............................................................
D
Ethanol .......................
Corn starch ..............................................................
E
Ethanol .......................
Starches from crop residue and annual covercrops
F
Biodiesel, renewable
diesel, jet fuel and heating oil.
Soy bean oil; Oil from annual covercrops; Algal oil;
Biogenic waste oils/fats/greases; Non-food grade
corn oil; Camelina oil.
G
Biodiesel, heating oil ..
Canola/Rapeseed oil ................................................
H
Biodiesel, renewable
diesel, jet fuel and heating oil.
Soy bean oil; Oil from annual covercrops; Algal oil;
Biogenic waste oils/fats/greases; Non-food grade
corn oil Camelina oil.
I Naphtha, LPG ..............
J Ethanol ........................
K Ethanol .......................
Camelina oil .............................................................
Sugarcane ................................................................
Cellulosic Biomass from crop residue, slash, precommercial thinnings and tree residue, annual
covercrops,
switchgrass,
miscanthus,
napiergrass, giant reed, and energy cane; cellulosic components of separated yard waste; cellulosic components of separated food waste; and
cellulosic components of separated MSW.
Cellulosic Biomass from crop residue, slash, precommercial thinnings and tree residue, annual
covercrops,
switchgrass,
miscanthus,
napiergrass, giant reed and energy cane; cellulosic components of separated yard waste; cellulosic components of separated food waste; and
cellulosic components of separated MSW.
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L
Cellulosic Diesel, jet
fuel and heating oil.
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6
6
6
4
4
5
5
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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations
727
TABLE 1 TO § 80.1426—APPLICABLE D CODES FOR EACH FUEL PATHWAY FOR USE IN GENERATING RINS—Continued
Fuel type
M
N
Feedstock
Production process requirements
Renewable Gasoline
and Renewable Gasoline Blendstock.
Cellulosic Biomass from crop residue, slash, precommercial thinnings, tree residue, annual cover
crops; cellulosic components of separated yard
waste; cellulosic components of separated food
waste; and cellulosic components of separated
MSW.
Corn starch ..............................................................
Catalytic Pyrolysis, Gasification and Upgrading, Direct Fermentation, Fermentation and Upgrading,
all utilizing natural gas, biogas, and/or biomass
as the only process energy sources. Any process utilizing biogas and/or biomass as the only
process energy sources.
Fermentation; dry mill using natural gas, biomass,
or biogas for process energy.
Any ...........................................................................
3
Any ...........................................................................
5
Butanol .......................
O
Ethanol, renewable
diesel, jet fuel, heating
oil, and naphtha.
P Biogas .........................
*
*
*
*
The non-cellulosic portions of separated food
waste.
Landfills, sewage waste treatment plants, manure
digesters.
*
[FR Doc. 2011–31580 Filed 1–4–12; 8:45 am]
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5
]]>Agencies
[Federal Register Volume 77, Number 3 (Thursday, January 5, 2012)]
[Rules and Regulations]
[Pages 700-727]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-31580]
[[Page 699]]
Vol. 77
Thursday,
No. 3
January 5, 2012
Part V
Environmental Protection Agency
-----------------------------------------------------------------------
40 CFR Part 80
Regulation of Fuels and Fuel Additives: Identification of Additional
Qualifying Renewable Fuel Pathways Under the Renewable Fuel Standard
Program; Direct Final Rule
Federal Register / Vol. 77 , No. 3 / Thursday, January 5, 2012 /
Rules and Regulations
[[Page 700]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 80
[EPA-HQ-OAR-2011-0542; FRL-9502-2]
RIN 2060-AR07
Regulation of Fuels and Fuel Additives: Identification of
Additional Qualifying Renewable Fuel Pathways Under the Renewable Fuel
Standard Program
AGENCY: Environmental Protection Agency (EPA).
ACTION: Direct final rule.
-----------------------------------------------------------------------
SUMMARY: EPA is issuing a direct final rule identifying additional fuel
pathways that EPA has determined meet the biomass-based diesel,
advanced biofuel or cellulosic biofuel lifecycle greenhouse gas (GHG)
reduction requirements specified in Clean Air Act section 211(o), the
Renewable Fuel Standard Program, as amended by the Energy Independence
and Security Act of 2007 (EISA). This direct final rule describes EPA's
evaluation of biofuels produced from camelina oil, energy cane, giant
reed, and napiergrass; it also includes an evaluation of renewable
gasoline and renewable gasoline blendstocks, as well as biodiesel from
esterification, and clarifies our definition of renewable diesel. We
are also finalizing two changes to regulation that were proposed on
July 1, 2011(76 FR 38844). The first change adds ID letters to pathways
to facilitate references to specific pathways. The second change adds
``rapeseed'' to the existing pathway for renewable fuel made from
canola oil.
This direct final rule adds these pathways to Table in regulation
as pathways which have been determined to meet one or more of the GHG
reduction thresholds specified in CAA 211(o), and assigns each pathway
a corresponding D-Code. It allows producers or importers of fuel
produced pursuant to these pathways to generate Renewable
Identification Numbers (RINs), providing that the fuel meets the other
requirements specified in the RFS regulations to qualify it as
renewable fuel.
DATES: This rule is effective on March 5, 2012 without further notice,
unless EPA receives adverse comment or a hearing request by February 6,
2012. If EPA receives a timely adverse comment or a hearing request, we
will publish a withdrawal in the Federal Register informing the public
that the portions of the rule with adverse comment will not take
effect.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2011-0542, by one of the following methods:
www.regulations.gov: Follow the on-line instructions for
submitting comments.
Email: a-and-r-docket@epa.gov, Attention Air and Radiation
Docket ID EPA-HQ-OAR-2011-0542
Fax: [Insert fax number].
Mail: Air and Radiation Docket, Docket No. EPA-HQ-OAR-
2011-0542, Environmental Protection Agency, Mailcode: 6406J, 1200
Pennsylvania Ave. NW., Washington, DC 20460.
Hand Delivery: EPA Docket Center, EPA/DC, EPA West, Room
3334, 1301 Constitution Ave. NW., Washington, DC, 20460, Attention Air
and Radiation Docket, ID No. EPA-HQ-OAR-2011-0542. Such deliveries are
only accepted during the Docket's normal hours of operation, and
special arrangements should be made for deliveries of boxed
information.
Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2011-0542. EPA's policy is that all comments received will be included
in the public docket without change and may be made available online at
www.regulations.gov, including any personal information provided,
unless the comment includes information claimed to be Confidential
Business Information (CBI) or other information whose disclosure is
restricted by statute. Do not submit information that you consider to
be CBI or otherwise protected through www.regulations.gov or email. The
www.regulations.gov Web site is an ``anonymous access'' system, which
means EPA will not know your identity or contact information unless you
provide it in the body of your comment. If you send an email comment
directly to EPA without going through www.regulations.gov your email
address will be automatically captured and included as part of the
comment that is placed in the public docket and made available on the
Internet. If you submit an electronic comment, EPA recommends that you
include your name and other contact information in the body of your
comment and with any disk or CD-ROM you submit. If EPA cannot read your
comment due to technical difficulties and cannot contact you for
clarification, EPA may not be able to consider your comment. Electronic
files should avoid the use of special characters, any form of
encryption, and be free of any defects or viruses. For additional
information about EPA's public docket visit the EPA Docket Center
homepage at https://www.epa.gov/epahome/dockets.htm.
Docket: All documents in the docket are listed in the
www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy.
Publicly available docket materials are available either electronically
in www.regulations.gov or in hard copy at the Air and Radiation Docket
and Information Center, EPA/DC, EPA West, Room 3334, 1301 Constitution
Ave. NW., Washington, DC. The Public Reading Room is open from 8:30
a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The
telephone number for the Public Reading Room is (202) 566-1744, and the
telephone number for the Air Docket is (202) 566-1742).
FOR FURTHER INFORMATION CONTACT: Vincent Camobreco, Office of
Transportation and Air Quality (MC6401A), Environmental Protection
Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone
number: (202) 564-9043; fax number: (202) 564-1686; email address:
camobreco.vincent@epa.gov.
SUPPLEMENTARY INFORMATION:
I. Why is EPA using a direct final rule?
EPA is publishing this rule without a prior proposed rule because
we view this as a noncontroversial action. These new pathway
determinations did not require new agricultural sector modeling and
involved relatively straightforward analyses that largely relied upon
work done for the RFS2 final rule. If EPA receives relevant adverse
comment or a hearing request on a distinct provision of this
rulemaking, we will publish a timely withdrawal in the Federal Register
indicating which portion of the rule is being withdrawn. Any distinct
amendment, paragraph, or section of today's rule not withdrawn will
become effective on the date set out above.
In the ``Proposed Rules'' section of today's Federal Register, we
are publishing a separate document that will serve as the proposed rule
to update Table 1 of Sec. 80.1426 to add any additional renewable fuel
production pathways or regulatory provisions which may be withdrawn
from the direct final rule. We will not institute a second comment
period on this action. Any parties interested in commenting must do so
at this time. For further information about commenting on this rule,
see the ADDRESSES section of this document. We will address all public
[[Page 701]]
comments in any subsequent final rule based on the proposed rule.
II. Does this action apply to me?
Entities potentially affected by this action are those involved
with the production, distribution, and sale of transportation fuels,
including gasoline and diesel fuel or renewable fuels such as ethanol
and biodiesel. Regulated categories and entities affected by this
action include:
------------------------------------------------------------------------
Examples of
NAICS \1\ SIC \2\ potentially
Category Codes Codes regulated
entities
------------------------------------------------------------------------
Industry....................... 324110 2911 Petroleum
Refineries.
Industry....................... 325193 2869 Ethyl alcohol
manufacturing.
Industry....................... 325199 2869 Other basic
organic chemical
manufacturing.
Industry....................... 424690 5169 Chemical and
allied products
merchant
wholesalers.
Industry....................... 424710 5171 Petroleum bulk
stations and
terminals.
Industry....................... 424720 5172 Petroleum and
petroleum
products
merchant
wholesalers.
Industry....................... 454319 5989 Other fuel
dealers.
------------------------------------------------------------------------
\1\ North American Industry Classification System (NAICS)
\2\ Standard Industrial Classification (SIC) system code.
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. This table lists the types of entities that EPA is now aware
could be potentially regulated by this action. Other types of entities
not listed in the table could also be regulated. To determine whether
your entity is regulated by this action, you should carefully examine
the applicability criteria of Part 80, subparts D, E and F of title 40
of the Code of Federal Regulations. If you have any question regarding
applicability of this action to a particular entity, consult the person
in the preceding FOR FURTHER INFORMATION CONTACT section above.
III. What should I consider as I prepare my comments for EPA?
A. Submitting information claimed as CBI. Do not submit information
you claim as CBI to EPA through www.regulations.gov or email. Clearly
mark the part or all of the information that you claim to be CBI. For
CBI information in a disk or CD ROM that you mail to EPA, mark the
outside of the disk or CD ROM as CBI and then identify electronically
within the disk or CD ROM the specific information that is claimed as
CBI). In addition to one complete version of the comment that includes
information claimed as CBI, a copy of the comment that does not contain
the information claimed as CBI must be submitted for inclusion in the
public docket. Information so marked will not be disclosed except in
accordance with procedures set forth in 40 CFR part 2.
B. Tips for Preparing Your Comments. When submitting comments,
remember to:
Identify the rulemaking by docket number and other
identifying information (subject heading, Federal Register date and
page number).
Follow directions--The agency may ask you to respond to
specific questions or organize comments by referencing a Code of
Federal Regulations (CFR) part or section number.
Explain why you agree or disagree; suggest alternatives
and substitute language for your requested changes.
Describe any assumptions and provide any technical
information and/or data that you used.
If you estimate potential costs or burdens, explain how
you arrived at your estimate in sufficient detail to allow for it to be
reproduced.
Provide specific examples to illustrate your concerns, and
suggest alternatives.
Explain your views as clearly as possible, avoiding the
use of profanity or personal threats.
Make sure to submit your comments by the comment period
deadline identified.
C. Docket Copying Costs. You may be charged a reasonable fee for
photocopying docket materials, as provided in 40 CFR part 2.
IV. Identification of additional qualifying renewable fuel pathways
under the renewable fuel standard (RFS) program
EPA is issuing a direct final rule to identify in the RFS
regulations additional renewable fuel production pathways that we have
determined meet the greenhouse gas (GHG) reduction requirements of the
RFS program. This direct final rule describes EPA's evaluation of:
Camelina Oil (New Feedstock)
Biodiesel and renewable diesel (including jet fuel and
heating oil) -- qualifying as biomass-based diesel and advanced biofuel
Naphtha and liquefied petroleum gas (LPG) -- qualifying as
advanced biofuel
Energy Cane, Giant Reed, and Napiergrass Cellulosic Biomass (New
Feedstocks)
Ethanol, renewable diesel (including renewable jet fuel
and heating oil), and naphtha -- qualifying as cellulosic biofuel
Renewable Gasoline and Renewable Gasoline Blendstock (New Fuel Types)
Produced from crop residue, slash, pre-commercial
thinnings, tree residue, annual cover crops, and cellulosic components
of separated yard waste, separated food waste, and separated municipal
solid waste (MSW)
Using the following processes -- all utilizing natural
gas, biogas, and/or biomass as the only process energy sources --
qualifying as cellulosic biofuel:
[cir] Thermochemical pyrolysis
[cir] Thermochemical gasification
[cir] Biochemical direct fermentation
[cir] Biochemical fermentation with catalytic upgrading
[cir] Any other process that uses biogas and/or biomass as the only
process energy sources
Esterification (New Production Process)
Process used to produce biodiesel from soy bean oil, oil
from annual covercrops, algal oil, biogenic waste oils/fats/greases,
non-food grade corn oil, Canola/rapeseed oil, and camelina oil--
qualifying as biomass-based diesel and advanced biofuel
This direct final rule adds these pathways to Table 1 to Sec.
80.1426 and assigns each pathway one or more D-Codes. This final rule
allows producers or importers of fuel produced under these pathways to
generate Renewable Identification Numbers (RINs) in accordance with the
RFS regulations, providing that the fuel meets other definitional
criteria for renewable fuel.
Determining whether a fuel pathway satisfies the CAA's lifecycle
GHG
[[Page 702]]
reduction thresholds for renewable fuels requires a comprehensive
evaluation of the lifecycle GHG emissions of the renewable fuel as
compared to the lifecycle GHG emissions of the baseline gasoline or
diesel fuel that it replaces. As mandated by CAA section 211(o), the
GHG emissions assessments must evaluate the aggregate quantity of GHG
emissions (including direct emissions and significant indirect
emissions such as significant emissions from land use changes) related
to the full fuel lifecycle, including all stages of fuel and feedstock
production, distribution, and use by the ultimate consumer.
In examining the full lifecycle GHG impacts of renewable fuels for
the RFS program, EPA considers the following:
Feedstock production--based on agricultural sector models
that include direct and indirect impacts of feedstock production
Fuel production--including process energy requirements,
impacts of any raw materials used in the process, and benefits from co-
products produced.
Fuel and feedstock distribution--including impacts of
transporting feedstock from production to use, and transport of the
final fuel to the consumer.
Use of the fuel--including combustion emissions from use
of the fuel in a vehicle.
Many of the pathways evaluated in this rulemaking rely on a
comparison to the lifecycle GHG analysis work that was done as part of
the Renewable Fuel Standard Program (RFS2) Final Rule, published March
26, 2010. The evaluations here rely on comparisons to the existing
analysis. EPA plans to periodically review and revise the methodology
and assumptions associated with calculating the GHG emissions from all
renewable fuel pathways.
A. Analysis of Lifecycle Greenhouse Gas Emissions for Biodiesel,
Renewable Diesel, Jet Fuel, Naphtha, and Liquefied Petroleum Gas (LPG)
Produced From Camelina Oil
1. Feedstock Production
Camelina sativa (camelina) is an oilseed crop within the flowering
plant family Brassicaceae that is native to Northern Europe and Central
Asia. Camelina's suitability to northern climates and low moisture
requirements allows it to be grown in areas that are unsuitable for
other major oilseed crops such as soybeans, sunflower, and canola/
rapeseed. Camelina also requires the use of little to no tillage.\1\
Compared to many other oilseeds, camelina has a relatively short
growing season (less than 100 days), and can be grown either as a
spring annual or in the winter in milder climates. \2\ \3\ Camelina can
also be used to break the continuous planting cycle of certain grains,
effectively reducing the disease, insect, and weed pressure in fields
planted with such grains (like wheat) in the following year.\4\
---------------------------------------------------------------------------
\1\ Putnam, D.H., J.T. Budin, L.A. Field, and W.M. Breene. 1993.
Camelina: A promising low-input oilseed. p. 314-322. In: J. Janick
and J.E. Simon (eds.), New crops. Wiley, New York.
\2\ Moser, B.R., Vaughn, S.F. 2010. Evaluation of Alkyl Esters
from Camelina Sativa Oil as Biodiesel and as Blend Components in
Ultra Low Sulfur Diesel Fuel. Bioresource Technology. 101:646-653.
\3\ McVay, K.A., and P.F. Lamb. 2008. Camelina production in
Montana. MSU Ext. MT200701AG (revised). https://msuextension.org/publica[not]tions/AgandNaturalResources/MT200701AG.pdf.
\4\ Putnam et al., 1993.
---------------------------------------------------------------------------
Although camelina has been cultivated in Europe in the past for use
as food, medicine, and as a source for lamp oil, commercial production
using modern agricultural techniques has been limited.\5\ In addition
to being used as a renewable fuel feedstock, small quantities of
camelina (less than 5% of total U.S. camelina production) are currently
used as a dietary supplement and in the cosmetics industry.
Approximately 95% of current US production of camelina has been used
for testing purposes to evaluate its use as a feedstock to produce
primarily jet fuel.\6\ The FDA has not approved camelina for food uses,
although it has approved the inclusion of certain quantities of
camelina meal in commercial feed.\7\
---------------------------------------------------------------------------
\5\ Lafferty, Ryan M., Charlie Rife and Gus Foster. 2009. Spring
camelina production guide for the Central High Plains. Blue Sun
Biodiesel special publication. Blue Sun Agriculture Research &
Development, Golden, CO. https://www.gobluesun.com/upload/Spring%20Cam-elina%20Production%20Guide%202009.pdf.
\6\ Telephone conversation with Scott Johnson, Sustainable Oils,
January 11, 2011.
\7\ See https://agr.mt.gov/camelina/FDAletter11-09.pdf.
---------------------------------------------------------------------------
Camelina is currently being grown on approximately 50,000 acres of
land in the U.S., primarily in Montana, eastern Washington, and the
Dakotas.\8\ USDA does not systematically collect camelina production
information; therefore data on historical acreage is limited. However,
available information indicates that camelina has been grown on trial
plots in 12 U.S. states.\9\
---------------------------------------------------------------------------
\8\ McCormick, Margaret. ``Oral Comments of Targeted Growth,
Incorporated'' Submitted to the EPA on June 9, 2009.
\9\ See https://www.camelinacompany.com/Marketing/PressRelease.aspx?Id=25.
---------------------------------------------------------------------------
For the purposes of analyzing the lifecycle GHG emissions of
camelina, EPA has considered the likely production pattern for camelina
grown for biofuel production. Given the information currently
available, camelina is expected to be primarily planted in the U.S. as
a rotation crop on acres that would otherwise remain fallow during the
camelina planting. Since substituting fallow land with camelina
production would not typically displace another crop, EPA does not
believe new acres would need to be brought into agricultural use to
increase camelina production. In addition, camelina currently has only
limited high-value niche markets for uses other than renewable fuels.
Unlike commodity crops that are tracked by USDA, camelina does not have
a well-established, internationally traded market that would be
significantly affected by an increase in the use of camelina to produce
biofuels. For these reasons, which are described in more detail below,
EPA has determined that production of camelina-based biofuels is not
expected to result in significant GHG emissions related to direct land
use change since it is grown on fallow land. Furthermore, due to the
limited non-biofuel uses for camelina, production of camelina-based
biofuels is not expected to have a significant impact on other
agricultural crop production or commodity markets (either camelina or
other crop markets) and consequently would not result in significant
GHG emissions related to indirect land use change. To the extent
camelina-based biofuel production decreases the demand for alternative
biofuels, some with higher GHG emissions, this biofuel could have some
beneficial GHG impact. However, it is uncertain which mix of biofuel
sources the market will demand so this potential GHG impact cannot be
quantified.
a. Growing Practices
Current market conditions indicate that camelina will most likely
be grown in rotation with wheat on dryland wheat acres replacing a
period that they would otherwise be left fallow.\10\ In areas with
lower precipitation, dryland wheat farmers currently leave acres fallow
once every three to four years to allow additional moisture and
nutrients to accumulate and to control pests. Current research
indicates that camelina could be introduced into this rotation in
certain areas without adversely impacting moisture or nutrient
accumulation (see Figure 1). Because camelina has shallow roots with
drought resistant characteristics, the
[[Page 703]]
land can be returned to wheat cultivation the following year with
moisture and soil nutrients intact quantitatively similar to a fallow
year.\11\ In addition, camelina uses the same equipment for harvesting
as wheat; therefore, farmers would not need to invest in new equipment
to add camelina to the rotation with wheat.\12\
---------------------------------------------------------------------------
\10\ See Shonnard, D. R., Williams, L., & Kalnes, T. N. 2010.
Camelina-Derived Jet Fuel and Diesel: Sustainable Advanced
Biodiesel. Environmental Progress & Sustainable Energy, 382-392.
\11\ See Shonnard et al., 2010; Lafferty et al., 2009.
\12\ Wheeler, P and F. Guillen-Portal. 2007. Camelina Production
in Montana: A survey study sponsored by Targeted Growth, Inc. and
Barkley Ag. Enterprises, LLP (unpublished).
---------------------------------------------------------------------------
BILLING CODE 6560-50-P
[[Page 704]]
[GRAPHIC] [TIFF OMITTED] TR05JA12.006
BILLING CODE 6560-50-C
[[Page 705]]
b. Land Availability
USDA estimates that there are approximately 60 million acres of
wheat in the U.S.\13\ USDA and wheat state cooperative extension
reports through 2008 indicate that 83% of U.S. wheat production is
under non-irrigated, dryland conditions. Of the approximately 50
million non-irrigated acres, at least 45% are estimated to follow a
wheat/fallow rotation. Thus, approximately 22 million acres are
potentially suitable for camelina production. However, according to
industry projections, only about 9 million of these wheat/fallow acres
have the appropriate climate, soil profile, and market access for
camelina production.\14\ Therefore, our analysis uses the estimate that
only 9 million wheat/fallow acres are available for camelina
production.
---------------------------------------------------------------------------
\13\ 2009 USDA Baseline. See https://www.ers.usda.gov/publications/oce091/.
\14\ Johnson, S. and McCormick, M., Camelina: an Annual Cover
Crop Under 40 CFR Part 80 Subpart M, Memorandum, dated November 5,
2010.
---------------------------------------------------------------------------
c. Projected Volumes
Based on these projections of land availability, EPA estimates that
at current yields (approximately 800 pounds per acre), approximately
100 million gallons (MG) of camelina-based renewable fuels could be
produced with camelina grown in rotation with existing crop acres
without having direct land use change impacts. Also, since camelina
will likely be grown on fallow land and thus not displace any other
crop and since camelina currently does not have other significant
markets, expanding production and use of camelina for biofuel purposes
is not likely to have other agricultural market impacts and therefore,
would not result in any significant indirect land use impacts.\15\ This
assessment is based on a three year rotation cycle in which only one
third of the 9 million available acres would be fallow in any given
year. Yields of camelina are expected to approach the yields of similar
oilseed crops over the next few years, as experience with growing
camelina improves cultivation practices and the application of existing
technologies are more widely adopted.\16\ Yields of 1650 pounds per
acre have been achieved on test plots, and are in line with expected
yields of other oilseeds such as canola/rapeseed. Assuming average US
yields of 1650 pounds per acre,\17\ approximately 200 MG of camelina-
based renewable fuels could be produced on existing wheat/fallow acres.
Finally, if investment in new seed technology allows yields to increase
to levels assumed by Shonnard et al (3000 pounds per acre),
approximately 400 MG of camelina-based renewable fuels could be
produced on existing acres.\18\ Depending on future crop yields, we
project that roughly 100 MG to 400 MG of camelina-based biofuels could
be produced on currently fallow land with no impacts on land use.\19\
---------------------------------------------------------------------------
\15\ Wheeler, P. and Guillen-Portal F. 2007. Camelina Production
in Montana: A survey study sponsored by Targeted Growth, Inc. and
Barkley Ag. Enterprises, LLP.
\16\ See Hunter, J and G. Roth. 2010. Camelina Production and
Potential in Pennsylvania, Penn State University Agronomy Facts 72.
See https://pubs.cas.psu.edu/freepubs/pdfs/uc212.pdf.
\17\ Ehrensing, D.T. and S.O. Guy. 2008. Oilseed Crops--
Camelina. Oregon State Univ. Ext. Serv. EM8953-E. See https://extension.oregonstate.edu/catalog/pdf/em/em8953-e.pdf; McVay & Lamb,
2008.
\18\ See Shonnard et al., 2010.
\19\ This assumes no significant adverse climate impacts on
world agricultural yields over the analytical timeframe.
---------------------------------------------------------------------------
d. Indirect Impacts
Although wheat can in some cases be grown in rotation with other
crops such as lentils, flax, peas, garbanzo, and millet, cost and
benefit analysis indicate that camelina is most likely to be planted on
soil with lower moisture and nutrients where other rotation crops are
not viable.\20\ Because expected returns on camelina are relatively
uncertain, farmers are not expected to grow camelina on land that would
otherwise be used to grow cash crops with well established prices and
markets. Instead, farmers are most likely to grow camelina on land that
would otherwise be left fallow for a season. The opportunity cost of
growing camelina on this type of land is much lower. As previously
discussed, this type of land represents the 9 million acres currently
being targeted for camelina production. Current returns on camelina are
relatively low ($13.24 per acre), given average yields of approximately
800 pounds per acre and the current contract price of $0.145 per
pound.\21\ See Table 1. For comparison purposes, the USDA projections
for wheat returns are between $88-$105 per acre between 2010 and 2020.
Over time, advancements in seed technology, improvements in planting
and harvesting techniques, and higher input usage could significantly
increase future camelina yields and returns.
---------------------------------------------------------------------------
\20\ See Lafferty et al., 2009; Shonnard et al., 2010;
Sustainable Oils Memo dated November 5, 2010,
\21\ Wheeler & Guillen-Portal, 2007.
\22\ See Sustainable Oils Memo dated November 5, 2010,
\23\ Based on yields technically feasible. See McVey and Lamb,
2008; Ehrenson & Guy, 2008.
\24\ Adapted from Shonnard et al, 2010.
Table 1--Camelina Costs and Returns
----------------------------------------------------------------------------------------------------------------
Inputs Rates 2010 Camelina \22\ 2022 Camelina \23\ 2030 Camelina \24\
----------------------------------------------------------------------------------------------------------------
Herbicides:
Glysophate (Fall)........... 16 oz. ( $0.39/oz) $7.00............. $7.00............. $7.00.
Glysophate (Spring)......... 16 oz. ( $0.39/oz) $7.00............. $7.00............. $7.00.
Post........................ 12 oz ( $0.67/oz). $8.00............. $8.00............. $8.00.
Seed:
Camelina seed............... $1.44/lb.......... $5.76............. $7.20............. $7.20
(4 lbs/acre)...... (5 lbs/acre)...... (5 lbs/acre).
Fertilizer:
Nitrogen Fertilizer......... $1/pd............. $25.00............ $40.00............ $75
(25 lb/acre)...... (40 lb/acre)...... (75 lbs/acre).
Phosphate Fertilizer........ $1/pd............. $15.00............ $15.00............ $15
(15 lb/acre)...... (15 lb/acre)...... (15 lb/acre).
-----------------------------------------------------------
Sub-Total............... .................. $67.76............ $84.20............ $119.20.
-----------------------------------------------------------
Logistics:
Planting Trip............... .................. $10.00............ $10.00............ $10.00.
Harvest & Hauling........... .................. $25.00............ $25.00............ $25.00.
-----------------------------------------------------------
[[Page 706]]
Total Cost.............. .................. $102.76........... $119.20........... $154.20.
===========================================================
Yields.......................... lb/acre........... 800............... 1650.............. 3000.
Price........................... $/lb.............. $0.145............ $0.120............ $0.090.
Total Revenue at avg prod/ .................. $116.00........... $198.............. $270.
pricing.
Returns..................... .................. $13.24............ $78.80............ $115.80.
----------------------------------------------------------------------------------------------------------------
While replacing the fallow period in a wheat rotation is expected
to be the primary means by which the majority of all domestic camelina
is commercially harvested in the short- to medium- term, in the long
term camelina may expand to other regions and growing methods.\25\ For
example, if camelina production expanded beyond the 9 million acres
assumed available from wheat fallow land, it could impact other crops.
However, as discussed above this is not likely to happen in the near
term due to uncertainties in camelina financial returns. Camelina
production could also occur in areas where wheat is not commonly grown.
For example, testing of camelina production has occurred in Florida in
rotation with kanaf, peanuts, cotton, and corn. However, only 200 acres
of camelina were harvested in 2010 in Florida. While Florida acres of
camelina are expected to be higher in 2011, very little research has
been done on growing camelina in Florida. For example, little is known
about potential seedling disease in Florida or how camelina may be
affected differently than in colder climates.\26\ Therefore, camelina
grown outside of a wheat fallow situation was not considered as part of
this analysis.
---------------------------------------------------------------------------
\25\ See Sustainable Oils Memo dated November 5, 2010 for a map
of the regions of the country where camelina is likely to be grown
in wheat fallow conditions.
\26\ Wright & Marois, 2011.
---------------------------------------------------------------------------
The determination in this final rule is based on our projection
that camelina is likely to be produced on what would otherwise be
fallow land. However, the rule applies to all camelina regardless of
where it is grown. EPA does not expect that significant camelina would
be grown on non-fallow land, and small quantities that may be grown
elsewhere and used for biofuel production will not significantly impact
our analysis.
Furthermore, although we expect most camelina used as a feedstock
for renewable fuel production that would qualify in the RFS program
would be grown in the U.S., today's rule would apply to qualifying
renewable fuel made from camelina grown in any country. For the same
reasons that pertain to U.S. production of camelina, we expect that
camelina grown in other countries would also be produced on land that
would otherwise be fallow and would therefore have no significant land
use change impacts. The renewable biomass provisions under the Energy
Independence and Security Act would prohibit direct land conversion
into new agricultural land for camelina production for biofuel
internationally. Additionally, any camelina production on existing
cropland internationally would not be expected to have land use impacts
beyond what was considered for international soybean production
(soybean oil is the expected major feedstock source for U.S. biodiesel
fuel production and thus the feedstock of reference for the camelina
evaluation). Because of these factors along with the small amounts of
fuel potentially coming from other countries, we believe that
incorporating fuels produced in other countries will not impact our
threshold analysis for camelina-based biofuels.
e. Crop Inputs
For comparison purposes, Table 2 shows the inputs required for
camelina production compared to the FASOM agricultural input
assumptions for soybeans. Since yields and input assumptions vary by
region, a range of values for soybean production are shown in Table 2.
The camelina input values in Table 2 represent average values, camelina
input values will also vary by region, however, less data is available
comparing actual practices by region due to limited camelina
production. More information on camelina inputs is available in
materials provided in the docket.
[GRAPHIC] [TIFF OMITTED] TR05JA12.007
Regarding crop inputs per acre, it should be noted that camelina
has a higher percentage of oil per pound of seed than soybeans.
Soybeans are approximately 18% oil, therefore crushing one pound of
soybeans yields
[[Page 707]]
0.18 pounds of oil. In comparison, camelina is approximately 36% oil,
therefore crushing one pound of camelina yields 0.36 pounds of oil. The
difference in oil yield is taken into account when calculating the
emissions per mmBTU included in Table 2. As shown in Table 2, GHG
emissions from feedstock production for camelina and soybeans are
relatively similar when factoring in variations in oil yields per acre
and fertilizer, herbicide, pesticide, and petroleum use.
In summary, EPA concludes that the agricultural inputs for growing
camelina are similar to those for growing soy beans, direct land use
impact is expected to be negligible due to planting on land that would
be otherwise fallow, and the limited production and use of camelina
indicates no expected impacts on other crops and therefore no indirect
land use impacts.
f. Crushing and Oil Extraction
We also looked at the seed crushing and oil extraction process and
compared the lifecycle GHG emissions from this stage for soybean oil
and camelina oil. As discussed above, camelina seeds produce more oil
per pound than soybeans. As a result, the lifecycle GHG emissions
associated with crushing and oil extraction are lower for camelina than
soybeans, per pound of vegetable oil produced. Table 3 summarizes data
on inputs, outputs and estimated lifecycle GHG emissions from crushing
and oil extraction. The data on soybean crushing comes from the RFS2
final rule, based on a process model developed by USDA-ARS.\27\ The
data on camelina crushing is from Shonnard et al. (2010).
---------------------------------------------------------------------------
\27\ A. Pradhan, D.S. Shrestha, A. McAloon, W. Yee, M. Haas,
J.A. Duffield, H. Shapouri, September 2009, ``Energy Life-Cycle
Assessment of Soybean Biodiesel'', United States Department of
Agriculture, Office of the Chief Economist, Office of Energy Policy
and New Uses, Agricultural Economic Report Number 845.
Table 3--Comparison of Camelina and Soybean Crushing and Oil Extraction
----------------------------------------------------------------------------------------------------------------
Item Soybeans Camelina Units
----------------------------------------------------------------------------------------------------------------
Material Inputs:
Beans or Seeds.................. 5.38 2.90 Lbs.
Energy Inputs:
Electricity..................... 374 47 Btu.
Natural Gas & Steam............. 1,912 780 Btu.
Outputs:
Refined vegetable oil........... 1.00 1.00 Lbs.
Meal............................ 4.08 1.85 Lbs.
GHG Emissions................... 213 64 gCO2e/lb refined oil.
----------------------------------------------------------------------------------------------------------------
2. Feedstock Distribution, Fuel Distribution, and Fuel Use
For this analysis, EPA projects that the feedstock distribution
emissions will be the same for camelina and soybean oil. To the extent
that camelina contains more oil per pound of seed, as discussed above,
the energy needed to move the camelina would be lower than soybeans per
gallon of fuel produced. To the extent that camelina is grown on more
disperse fallow land than soybean and would need to be transported
further, the energy needed to move the camelina could be higher than
soybean. Based on this, we believe the assumption to use the same
distribution impacts for camelina as soybean is a reasonable estimate
of the GHG emissions from camelina feedstock distribution. In addition,
the final fuel produced from camelina is also expected to be similar in
composition to the comparable fuel produced from soybeans, therefore we
are assuming GHG emissions from the distribution and use of fuels made
from camelina will be the same as emissions of fuel produced from
soybeans.
3. Fuel Production
There are two main fuel production processes used to convert
camelina oil into fuel. The trans-esterification process produces
biodiesel and a glycerin co-product. The hydrotreating process can be
configured to produce renewable diesel either primarily as diesel fuel
(including heating oil) or primarily as jet fuel. Possible additional
products from hydrotreating include naphtha, LPG, and propane. Both
processes and the fuels produced are described in the following
sections. Both processes use camelina oil as a feedstock and camelina
crushing is also included in the analysis.
a. Biodiesel
For this analysis, we assumed the same biodiesel production
facility designs and conversion efficiencies as modeled for biodiesel
produced from soybean oil and canola/rapeseed oil. Camelina oil
biodiesel is produced using the same methods as soybean oil biodiesel,
therefore plant designs are assumed to not significantly differ between
fuels made from these feedstocks. As was the case for soybean oil
biodiesel, we have not projected in our assessment of camelina oil
biodiesel any significant improvements in plant technology.
Unanticipated energy saving improvements would further improve GHG
performance of the fuel pathway.
The glycerin produced from camelina biodiesel production is
equivalent to the glycerin produced from the existing biodiesel
pathways (e.g., based on soy oil) that were analyzed as part of the
RFS2 final rule. Therefore the same co-product credit would apply to
glycerin from camelina biodiesel as glycerin produced in the biodiesel
pathways modeled for the RFS2 final rule. The assumption is that the
GHG reductions associated with the replacement of residual oil with
glycerin on an energy equivalent basis represents an appropriate
midrange co-product credit of biodiesel produced glycerin.
As part of our RFS2 proposal, we assumed the glycerin would have no
value and would effectively receive no co-product credits in the soy
biodiesel pathway. We received numerous comments, however, stating that
the glycerin would have a beneficial use and should generate co-product
benefits. Therefore, the biodiesel glycerin co-product determination
made as part of the RFS2 final rule took into consideration the
possible range of co-product credit results. The actual co-product
benefit will be based on what products are replaced by the glycerin and
what new uses develop for the co-product glycerin. The total amount of
glycerin produced from the biodiesel industry will actually be used
across a number of different markets with different GHG impacts. This
could include for example, replacing
[[Page 708]]
petroleum glycerin, replacing fuel products (residual oil, diesel fuel,
natural gas, etc.), or being used in new products that don't have a
direct replacement, but may nevertheless have indirect effects on the
extent to which existing competing products are used. The more
immediate GHG reduction credits from glycerin co-product use will
likely range from fairly high reduction credits when petroleum glycerin
is replaced to lower reduction credits if it is used in new markets
that have no direct replacement product, and therefore no replaced
emissions.
EPA does not have sufficient information (and received no relevant
comments as part of the RFS2 rule) on which to allocate glycerin use
across the range of likely uses. Therefore, EPA believes that the
approach used in RFS2 of picking a surrogate use for modeling purposes
in the mid-range of likely glycerin uses, and the GHG emissions results
tied to such use, is reasonable. The replacement of an energy
equivalent amount of residual oil is a simplifying assumption
determined by EPA to reflect the mid-range of possible glycerin uses in
terms of GHG credits. EPA believes that it is appropriately
representative of GHG reduction credit across the possible range
without necessarily biasing the results toward high or low GHG impact.
Given the fundamental difficulty of predicting possible glycerin uses
and impacts of those uses many years into the future under evolving
market conditions, EPA believes it is reasonable to use the more
simplified approach to calculating co-product GHG benefit associated
with glycerin production.
Given the fact that GHG emissions from camelina-based biodiesel
would be similar to the GHG emissions from soybean- based biodiesel at
all stages of the lifecycle but would not result in land use change as
was the case for soy oil used as a feedstock, we believe biodiesel from
camelina oil will also meet the 50% GHG emissions reduction threshold
to qualify as a biomass based diesel and an advanced fuel. Therefore,
EPA is including biodiesel produced from camelina oil under the same
pathways for which biodiesel made from soybean oil qualifies under the
RFS2 final rule.
b. Renewable Diesel (Including Jet Fuel and Heating Oil), Naphtha, and
LPG
The same feedstocks currently used for biodiesel production can
also be used in a hydrotreating process to produce a slate of products,
including diesel fuel, heating oil (defined as No. 1 or No. 2 diesel),
jet fuel, naphtha, LPG, and propane. Since the term renewable diesel is
defined to include the products diesel fuel, jet fuel and heating oil,
the following discussion uses the term renewable diesel to also include
diesel fuel, jet fuel and heating oil. The yield of renewable diesel is
relatively insensitive to feedstock source.\28\ While any propane
produced as part of the hydrotreating process will most likely be
combusted within the facility for process energy, the other co-products
that can be produced (i.e., renewable diesel, naphtha, LPG) are higher
value products that could be used as transportation fuels or, in the
case of naphtha, a blendstock for production of transportation fuel.
The hydrotreating process maximized for producing a diesel fuel
replacement as the primary fuel product requires more overall material
and energy inputs than transesterification to produce biodiesel, but it
also results in a greater amount of other valuable co-products as
listed above. The hydrotreating process can also be maximized for jet
fuel production which requires even more process energy than the
process optimized for producing a diesel fuel replacement, and produces
a greater amount of co-products per barrel of feedstock, especially
naphtha.
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\28\ Kalnes, T., N., McCall, M., M., Shonnard, D., R., 2010.
Renewable Diesel and Jet-Fuel Production from Fats and Oils.
Thermochemical Conversion of Biomass to Liquid Fuels and Chemicals,
Chapter 18, p. 475.
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Producers of renewable diesel from camelina have expressed interest
in generating RINs under the RFS2 program for the slate of products
resulting from the hydrotreating process. Our lifecycle analysis
accounts for the various uses of the co-products. There are two main
approaches to accounting for the co-products produced, the allocation
approach, and the displacement approach. In the allocation approach all
the emissions from the hydrotreating process are allocated across all
the different co-products. There are a number of ways to do this but
since the main use of the co-products would be to generate RINs as a
fuel product we allocate based on the energy content of the co-products
produced. In this case, emissions from the process would be allocated
equally to all the Btus produced. Therefore, on a per Btu basis all co-
products would have the same emissions. The displacement approach would
attribute all of the emissions of the hydrotreating process to one main
product and then account for the emission reductions from the other co-
products displacing alternative product production. For example, if the
hydrotreating process is configured to maximize diesel fuel replacement
production, all of the emissions from the process would be attributed
to diesel fuel, but we would then assume the other co-products were
displacing alternative products, for example, naphtha would displace
gasoline, LPG would displace natural gas, etc. This assumes the other
alternative products are not produced or used, so we would subtract the
emissions of gasoline production and use, natural gas production and
use, etc. This would show up as a GHG emission credit associated with
the production of diesel fuel replacement.
To account for the case where RINs are generated for the jet fuel,
naphtha and LPG in addition to the diesel replacement fuel produced, we
would not give the diesel replacement fuel a displacement credit for
these co-products. Instead, the lifecycle GHG emissions from the fuel
production processes would be allocated to each of the RIN-generating
products on an energy content basis. This has the effect of tending to
increase the fuel production lifecycle GHG emissions associated with
the diesel replacement fuel because there are less co-product
displacement credits to assign than would be the case if RINs were not
generated for the co-products.\29\ On the other hand, the upstream
lifecycle GHG emissions associated with producing and transporting the
plant oil feedstocks will be distributed over a larger group of RIN-
generating products. Assuming each product (except propane) produced
via the camelina oil hydrotreating process will generate RINs results
in higher lifecycle GHG emissions for diesel fuel replacement as
compared to the case where the co-products are not used to generate
RINs. This general principle is also true when the hydrotreating
process is maximized for jet fuel production. As a result, the worst
GHG performance (i.e., greatest lifecycle GHG emissions) for diesel
replacement fuel and jet fuel produced from camelina oil via
hydrotreating will occur when all of the co-products are RIN-generating
(we assume propane will be used for process energy). Thus, if these
fuels meet the 50% GHG reduction threshold for biomass based diesel or
advanced biofuel when co-products are RIN-generating, they will
[[Page 709]]
also do so in the case when RINs are not generated for co-products.
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\29\ For a similar discussion see page 46 of Stratton, R.W.,
Wong, H.M., Hileman, J.I. 2010. Lifecycle Greenhouse Gas Emissions
from Alternative Jet Fuels. PARTNER Project 28 report. Version 1.1.
PARTNER-COE-2010-001. June 2010, https://web.mit.edu/aeroastro/partner/reports/proj28/partner-proj28-2010-001.pdf.
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We have evaluated information about the lifecycle GHG emissions
associated with the hydrotreating process which can be maximized for
jet fuel or diesel replacement fuel production. Our evaluation
considers information published in peer-reviewed journal articles and
publicly available literature (Kalnes et al, 2010, Pearlson, M., N.,
2011,\30\ Stratton et al., 2010, Huo et al., 2008).\31\ Our analysis of
GHG emissions from the hydrotreating process is based on the mass and
energy balance data in Pearlson (2011) which analyzes a hydrotreating
process maximized for diesel replacement fuel production and a
hydrotreating process maximized for jet fuel production.\32\ This data
is summarized in Table 4.
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\30\ Pearlson, M., N. 2011. A Techno-Economic and Environmental
Assessment of Hydroprocessed Renewable Distillate Fuels.
\31\ Huo, H., Wang., M., Bloyd, C., Putsche, V., 2008. Life-
Cycle Assessment of Energy and Greenhouse Gas Effects of Soybean-
Derived Biodiesel and Renewable Fuels. Argonne National Laboratory.
Energy Systems Division. ANL/ESD/08-2. March 12, 2008.
\32\ We have also considered data submitted by companies
involved in the hydrotreating industry which is claimed as
confidential business information (CBI). The conclusions using the
CBI data are consistent with the analysis presented here.
\33\ Based on Pearlson (2011), Table 3.1 and Table 3.2.
Table 4--Hydrotreating Processes to Convert Camelina Oil Into Diesel Replacement Fuel and Jet Fuel\33\
----------------------------------------------------------------------------------------------------------------
Maximized for
diesel fuel Maximized for jet Units (per gallon of fuel
production fuel production produced)
----------------------------------------------------------------------------------------------------------------
Inputs:
Refined camelina oil................ 9.56 12.84 Lbs.
Hydrogen............................ 0.04 0.08 Lbs.
Electricity......................... 652 865 Btu.
Natural Gas......................... 23,247 38,519 Btu.
Outputs:
Diesel Fuel......................... 123,136 55,845 Btu.
Jet fuel............................ 23,197 118,669 Btu.
Naphtha............................. 3,306 17,042 Btu.
LPG................................. 3,084 15,528 Btu.
Propane............................. 7,454 9,881 Btu.
----------------------------------------------------------------------------------------------------------------
Table 5 compares lifecycle GHG emissions from oil extraction and
fuel production for soybean oil biodiesel and for camelina-based diesel
and jet fuel. The lifecycle GHG estimates for camelina oil diesel and
jet fuel are based on the input/output data summarized in Table 3 (for
oil extraction) and Table 4 (for fuel production). We assume that the
propane co-product does not generate RINs; instead, it is used for
process energy displacing natural gas. We also assume that the naphtha
is used as blendstock for production of transportation fuel to generate
RINs. In this case we assume that RINs are generated for the use of LPG
in a way that meets the EISA definition of transportation fuel, for
example it could be used in a nonroad vehicle. The lifecycle GHG
results in Table 5 represent the worst case scenario (i.e., highest GHG
emissions) because all of the eligible co-products are used to generate
RINs. This is because, as discussed above, lifecycle GHG emissions per
Btu of diesel or jet fuel would be lower if the naphtha or LPG is not
used to generate RINs and is instead used for process energy displacing
fossil fuel such as natural gas. Supporting information for the values
in Table 5, including key assumptions and data, is provided through the
docket.
Table 5--Fuel Production Lifecycle GHG Emissions (kgCO2e/mmBtu) \34\
--------------------------------------------------------------------------------------------------------------------------------------------------------
RIN-Generating
Feedstock Production process products Other co-products Oil extraction Processing Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Soybean Oil....................... Trans-Esterification. Biodiesel........... Glycerin............ 14 (1) 13
Camelina Oil...................... Trans-Esterification. Biodiesel........... Glycerin............ 4 (1) 3
Camelina Oil...................... Hydrotreating Diesel.............. Propane............. 4 8 12
Maximized for Diesel. Jet Fuel............
Naphtha.............
LPG.................
Camelina Oil...................... Hydrotreating Jet Fuel............ Propane............. 4 11 14
Maximized for Jet Diesel..............
Fuel. Naphtha.............
LPG.
--------------------------------------------------------------------------------------------------------------------------------------------------------
As discussed above, for a process that produces more than one RIN-
generating output (e.g., the hydrotreating process summarized in Table
5 which produces diesel replacement fuel, jet fuel, and naphtha) we
allocate lifecycle GHG emissions to the RIN generating products on an
energy equivalent basis. We then normalize the allocated lifecycle GHG
emissions per mmBtu of each fuel product. Therefore, each RIN-
generating product from the same process will be assigned equal
lifecycle GHG emissions per mmBtu from fuel processing. For example,
based on the
[[Page 710]]
lifecycle GHG estimates in Table 5 for the hydrotreating process
maximized to produce jet fuel, the jet fuel and the naphtha both have
lifecycle GHG emissions of 14 kgCO2e/mmBtu. For the same
reasons, the lifecycle GHG emissions from the jet fuel and naphtha will
stay equivalent if we consider upstream GHG emissions, such as
emissions associated with camelina cultivation and harvesting.
Lifecycle GHG emissions from fuel distribution and use could be
somewhat different for the jet fuel and naphtha, but since these stages
produce a relatively small share of the emissions related to the full
fuel lifecycle, the overall difference will be quite small.
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\34\ Lifecycle GHG emissions are normalized per mmBtu of RIN-
generating fuel produced. Totals may not be the sum of the rows due
to rounding error. Parentheses indicate negative numbers. Process
emissions for biodiesel production are negative because they include
the glycerin offset credit.
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Given that GHG emissions from camelina oil would be similar to the
GHG emissions from soybean oil at all stages of the lifecycle but would
not result in land use change emissions (soy oil feedstock did have a
significant land use change impact but still met a 50% GHG reduction
threshold), and considering differences in process emissions between
soybean biodiesel and camelina-based renewable diesel, we conclude that
renewable diesel from camelina oil will also meet the 50% GHG emissions
reduction threshold to qualify as biomass based diesel and advanced
fuel. Although some of the potential configurations result in fuel
production GHG emissions that are higher than fuel production GHG
emissions for soybean oil biodiesel, land use change emissions account
for approximately 80% of the soybean oil to biodiesel lifecycle GHGs.
Since camelina is assumed not to have land use change emissions, our
analysis shows that camelina renewable diesel will qualify for advanced
renewable fuel and biomass-based diesel RINs even for the cases with
the highest lifecycle GHGs (e.g., when all of the co-products are used
to generate RINs.) Because the lifecycle GHG emissions for RIN-
generating co-products are very similar, we can also conclude naphtha
and LPG produced from camelina oil will also meet the 50% GHG emissions
reduction threshold. If the facility does not actually generate RINs
for one or more of these co-products, we estimate that the lifecycle
GHG emissions related to the RIN-generating products would be lower,
thus renewable diesel (which includes diesel fuel, jet fuel, and
heating oil) from camelina would still meet the 50% emission reduction
threshold.
4. Summary
Current information suggests that camelina has limited niche
markets and will be produced on land that would otherwise remain
fallow. Therefore, increased production of camelina-based renewable
fuel is not expected to result in significant land use change
emissions. For the purposes of this analysis, EPA is projecting there
will be no land use emissions associated with camelina production for
use as a renewable fuel feedstock.
However, while production of camelina on acres that would otherwise
remain fallow is expected to be the primary means by which the majority
of all camelina is commercially harvested in the short- to medium-
term, in the long term camelina may expand to other growing methods and
lands if demand increases substantially beyond what EPA is currently
predicting. While the impacts are uncertain, there are some indications
demand could increase significantly. For example, camelina is included
under USDA's Biomass Crop Assistance Program (BCAP) and there is
growing support for the use of camelina oil in producing drop-in
alternative aviation fuels. EPA plans to monitor the expansion of
camelina production to verify whether camelina is primarily grown on
existing acres once camelina is produced at larger-scale volumes.
Similarly, we will consider market impacts if alternative uses for
camelina expand significantly beyond what was described in the above
analysis. Just as EPA plans to periodically review and revise the
methodology and assumptions associated with calculating the GHG
emissions from all renewable fuel feedstocks, EPA expects to review and
revise as necessary the analysis of camelina in the future.
Taking into account the assumption of no land use change emissions
when camelina is used to produce renewable fuel, and considering that
other sources of GHG emissions related to camelina biodiesel or
renewable diesel production have comparable GHG emissions to biodiesel
from soybean oil, we have determined that camelina-based biodiesel and
renewable diesel should be treated in the same manner as soy-based
biodiesel and renewable diesel in qualifying as biomass-based diesel
and advanced biofuel for purposes of RIN generation, since the GHG
emission performance of the camelina-based fuels will be at least as
good and in some respects better than that modeled for fuels made from
soybean oil. EPA found as part of the Renewable Fuel Standard final
rulemaking that soybean biodiesel resulted in a 57% reduction in GHG
emissions compared to the baseline petroleum diesel fuel. Furthermore,
approximately 80% of the lifecycle i
